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{{#Wiki_filter:200 ExelonWfI'i Exelon Generation~                                              Kennett Square, PA 19348 www.exeloncorp com TS 6.18.d TMl-21-012 April 13,2021 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555 Three Mile Island Nuclear Station, Unit 1 Renewed Facility Operating License No. DPR-50 NRC Docket No. 50-289
{{#Wiki_filter:}}
 
==Subject:==
Submittal of Changes to Technical Specifications Bases In accordance with the requirements of Three Mile Island Nuclear Station (TMI), Unit 1, Permanently Defueled Technical Specification 6.18.d, Exelon Generation Company, LLC, hereby submits a complete updated copy of the TMI, Unit 1, Technical Specifications (TS)
Bases, which includes the related TS. The enclosed Bases include changes implemented through the date of this letter.
If you have any questions or require further information, please contact Richard Gropp at 610-765-5512.
Respectfully, David P. Helker Sr. Manager, Licensing Exelon Generation Company, LLC
 
==Enclosure:==
Three Mile Island Nuclear Station, Unit 1, Technical Specifications and Bases cc:  w/ Enclosure USNRC Administrator, Region I NRC Project Manager, NMSS/DUWP/RDB - Three Mile Island, Units 1 and 2 W. DeHaas - Pennsylvania Bureau of Radiation Protection
 
Three Mile Island Nuclear Station, Unit 1 Technical Specifications and Bases
 
3/4. LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS 3/4.0 GENERAL ACTION REQUIREMENTS AND SURVEILLANCE REQUIREMENT APPLICABILITY 3.0.1 LCOs shall be met during the specified conditions in the TS, except as provided in 3.0.2.
3.0.2 Upon discovery of a failure to meet-an LCO, the required actions of the associated Conditions shall be met.
If the LCO is met or is no longer applicable prior to expiration of the specified completion time(s), completion of the required action(s) is not required, unless otherwise stated.
4.0.1 Surveillance requirements shall be met during the specified conditions in the applicability for' individual LCOs, unless otherwise stated in the surveillance requirements. 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 LCO. Failure to perform a surveillance within the specified frequency shall be failure to meet the LCO except as provided in 4.0.2.
4.0.2 If it is discovered that a surveillance was not performed within its specified frequency, then compliance with the requirement to declare the LCO 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. The delay period is only applicable when there is a reasonable expectation the surveillance will be met when performed.
If the surveillance is not performed within the delay period, the LCO must immediately be declared not met, and the applicable condition(s) must be entered.
When the surveillance is performed within the delay period and the surveillance is not met, the LCO must immediately be declared not met, and the applicable condition(s) must be entered.
4.0.3 The specified frequency for each SR is met if the surveillance is performed within 1.25 times the interval specified in the frequency, as measured from the previous performance.
                                                                                                  /
3/4-1 Amendment No. 297
 
BASES LCO 3.0.1 and LCO 3.0.2, and SR 4.0.1 through SR 4.0.3 delineate the actions to be taken for circumstances not directly provided for in the action requirements of individual specifications and whose occurrence would violate the intent of the specification.
LCO 3.0.1 establishes the applicability statement within each individual specification as the requirement for when the LCO is required to be met (i.e., when the facility is in the specified conditions of the applicability statement of each Specification).
LCO 3.0.2 establishes that upon discovery of a failure to meet an LCO, the associated actions shall be met. The completion time of each required action for an ACTIONS condition is applicable from the point in time-that an actions condition is entered. The required actions establish those remedial measures that must be taken within specified completion times when the requirements of an LCO are not met. This specification establishes that completion of the required actions within the specified completion times constitutes compliance with a specification.
Completing the required actions is not required when an LCO is met or is no longer applicable, unless otherwise stated in the individual specifications.
SR 4.0.1 establishes the requirement that SRs must be met during the specified conditions in the SRs for which the requirements of the LCO apply, unless otherwise specified in the individual SRs. This specification is to ensure that surveillances are performed in order to verify a
that facility conditions are within specified limits. Failure to meet surveillance within the specified frequency constitutes a failure to meet an LCO.
Variables are assumed to be within limits when the associated SRs have been met. Nothing in this Specification, however, is to be construed as implying that variables are within limits when the requirements of the surveillance(s) are known not to be met between required surveillance performances.
Surveillances do not have to be performed when the unit is in a specified condition for which the requirements of the associated LCO are not applicable, unless otherwise specified. Unplanned events may satisfy the requirements (including applicable acceptance criteria) for a given SR.
In this case, the unplanned event may be credited as fulfilling the performance of the SR. This allowance includes those SRs whose performance is normally precluded in a given specified condition.
Surveillances, including surveillances invoked by LCO required actions, do not have to be performed on inoperable equipment because the actions define the remedial measures that apply. Surveillances have to be met and performed in a~rdance with the specified frequency, prior to returning equipment to OPERABLE status.
SR 4.0.2 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a surveillance has not been performed within the specified frequency. A delay period of up to 24 hours or up to the limit of the specified frequency, whichever is greater, applies from the point in time that it is discovered that the required surveillance has not been performed in accordance with Surveillance Requirement 4.0.2 and not at the time that the specified frequency was not met 3/4-2 Amendment No. 297
 
The delay period provides an adequate time to perform surveillances that have been missed.
This delay period permits the performance of a surveillance before complying with required actions or other remedial measures that might preclude performance of the surveillance.
The basis for this delay period includes consideration of facility conditions, adequate planning, availability of personnel, the time required to perform the surveillance, the safety significance of the delay in completing the required surveillance, and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the requirements.
SR 4.0.2 is only applicable if there is a reasonable expectation the associated variables are within limits, and it is expected that the Surveillance will be met when performed. Many factors should be considered, such as the period of time since the Surveillance was last performed, or whether the Surveillance, or a portion thereof, has ever been performed, and any other indications, tests, or activities that might support the expectation that the Surveillance will be met when performed. The rigor of determining whether there is a reasonable expectation a Surveillance will be met when performed should increase based on the length of time since the last performance of the Surveillance. If the Surveillance has been performed recently, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable expectation that the Surveillance will be met when performed. For Surveillances that have not been performed for a long period or that have never been performed, a rigorous evaluation based on objective evidence should provide a high degree of confidence that the equipment is OPERABLE. The evaluation should be documented in sufficient detail to allow a knowledgeable individual to understand the basis for the determination.
Failure to comply with specified surveillance frequencies is expected to be an infrequent occurrence. Use of the delay period established by Surveillance Standard 4.0.2 is a flexibility which is not intended to be used repeatedly to extend surveillance intervals. While up to 24 hours or the limit of the specified frequency is provided to perform the missed surveillance, it is expected that the missed surveillance will be performed at the first reasonable opportunity. If a surveillance is not completed within the allowed delay period, then the variable is considered outside the specified limits and the completion times of the required actions for the applicable LCO conditions begin immediately upon expiration of the delay period. If a surveillance is failed within the delay period, then the variable is outside the specified limits and the completion times of the required actions for the applicable LCO conditions begin immediately upon failure of the surveillance.
Completion of the surveillance within the delay period allowed by this specification, or within the completion time of the actions, restores compliance.
SR 4.0.3 permits a 25% extension of the interval specified in the frequency. This extension facilitates Surveillance scheduling and considers facility conditions that may not be suitable for conducting the Surveillance (e.g., other ongoing surveillance or maintenance activities).
The 25% extension does not significantly degrade the reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any Surveillance is the verification of conformance with the SRs.
3/4-3 Amendment No. 297
 
3/4.1      HANDLING AND STORAGE OF IRRADIATED FUEL IN THE SPENT FUEL POOL 3/4.1.1    SPENT FUEL POOL WATER          LEVEL Applicabiljty Applies to the minimum level of water in the Spent Fuel Pool during handling of irradiated fuel in the Spent Fuel Pool.
Objective Ensures that assumptions of Fuel Handling Accident are maintained during handling of irradiated fuel in the Spent Fuel Pool.
Specification 3.1.1.1      Maintain Spent Fuel Pool level greater than 342'4" elevation.
3.1.1.2      With Spent Fuel Pool level less than 342'4" elevation, immediately suspend handling of irradiated fuel in the Spenf Fuel Pool.
SURVEILLANCE REQUIREMENTS 4.1.1.1      Verify Spent Fuel Pool level greater than or equal to 342'4" elevation every 7 days.
The top of fuel is at the 319'4" elevation. The FHA analysis assumes 23' of water above the fuel assemblies.- This dictates a minimum elevation of water in the Spent Fuel Pool of 342'4 *.
This specification provides the controls to ensure the assumptions of the accident analysis while fuel handling evolutions are in progress. This specification will have a SR 4.1.1.1 that will verify the Spent Fuel Pool water level on a frequency of 7 days.
The water contained in the spent fuel pool provides a medium for removal of decay heat from the stored fuel elements, normally via the spent fuel cooling system. The spent fuel pool water also provides shielding to reduce the general area radiation dose during both spent fuel handling and storage. The resultant 2-hour dose to a person at the exclusion area boundary and the 30-day dose at the low population zone are much less than 10 CFR 50.67 limits.
LCO 3.1.1.2 requires that when the water level in the SFP is lower than the required level, the movement of irradiated fuel assemblies in the SFP is to be "immediately" suspended.
"Immediately" as used in this completion time means the required action should be pursued without delay and in a controlled manner, such that the suspension of this activity shall not preclude completion of movement of an irradiated fuel assembly to a safe position. This effectively precludes a spent fuel handling accident from occurring in the SFP when the level is below the required elevation.
Although maintaining adequate spent fuel pool water level is essential to both decay heat removal and shielding effectiveness, the Technical Specification minimum water level limit is based upon maintaining the pool's iodine retention-effectiveness consistent with that assumed 3/4-4 Amendment No. 297
 
in the evaluation of the Post Permanent Shutdown-FHA analysis. The Post Permanent Shutdown FHA analysis assumes that a minimum of 23 feet of water is maintained above the stored fuel. This assumption allows the use of the pool iodine decontamination factor of 200 used in the associated offsite dose calculation.
* 3/4-5 Amendment No. 297
 
3/4.1.2      SPENT FUEL POOL BORON CONCENTRATION Applicability Applies to the minimum boron concentration in the Spent Fuel Pool during storage and handling of irradiated fuel in the Spent Fuel Pool.
Objective Ensures that assumptions of Storage Limitations are maintained to prevent inadvertent criticality in the Spent Fuel Pool.
Specification 3.1.2.1      Maintain Spent Fuel Pool boron concentration greater than or equal to 600 ppm.
3.1.2.2      With Spent Fuel Pool boron concentration less than 600 ppm, immediately suspend handling of irradiated fuel in the Spent Fuel Pool and immediately restore boron concentration per 3.1.2.1.
SURVEILLANCE REQUIREMENTS 4.1.2.1      Verify Spent Fuel Pool boron concentration greater than or equal to 600 ppm every 7 days.            -
The acceptance criteria for the fuel storage pool criticality analyses is that a keff of< 0.95 must be maintained for all postulated events. The storage racks are capable of maintaining this keff with unborated pool water at a temperature yielding the highest reactivity (assuming the storage restrictions of LCO 3.1.3 are met). Most abnormal storage locations will not result in an increase in the keff of the racks. However, it is possible to postulate events, such as the mis-loading of an assembly with a bumup and enrichment combination outside the acceptable area in Figure 3.1.3-1 and-3.1.3-2, or dropping an assembly between the pool wall and the fuel racks, which could lead to an increase in reactivity. For such events, credit is taken for the presence of boron in the pool water since the NRC does not require the assumption of two unlikely, independent, concurrent events to ensure protection against a criticality accident (double contingency principle). The reduction in keff, caused by the boron m6re than offsets the reactivity addition caused by credible accidents. This specification will have a Surveillance Requirement SR 4.1.2.1 that will verify the Spent Fuel Pool Boron on a frequency of 7- days.
LCO 3.1.2.2 requires that when the SFP boron concentration is less than 600 ppm, the movement of irradiated fuel assemblies in the SFP is to be "immediately" suspended.
"Immediately'' as used in this completion time means the required action should be pursued without delay and in a controlled manner, such that the suspension of this activity shall not preclude completion of movement of an irradiated fuel assembly to a safe position. This effectively precludes a spent fuel handling accident from occurring in the SFP when the boron concentration is below the required level.
3/4-6 Amendment No. 297
 
3/4.1.3    SPENT FUEL ASSEMBLY STORAGE Applicability Applles whenever any fuel assembly is stored in Storage Pool A or Storage Pool B of the Spent Fuel Pool.
Objective Ensures that assumptions of Storage Limitations are maintained to prevent inadvertent criticality in the Spent Fuel Pool.
Specification 3.1.3.1    The combination of initial enrichment and bumup of each spent fuel assembly stored in Storage Pool A and Storage Pool B, shall be within the acceptable region of Figure 3.1.3-1 or 3.1.3-2.
3.1.3.2    When requirement of 3.1.3.1 is not met, immediately initiate action to move the noncomplying fuel assembly to an acceptable configuration.
SURVEILLANCE REQUIREMENTS 4.1.3.1    Verify by administrative means the initial enrichment and bumup of the fuel assembly is in accordance with Figure 3.1.3-~ or Figure 3.1.3-2 prior to storing irradiated spent fuel in the Spent Fuel Pool A or Spent Fuel Pool B.
The function of the spent fuel storage racks is to support safety analyses and protect spent fuel assemblies from the time they are placed in the pool until they are shipped offsite. The spent fuel assembly storage LCO was derived from the need to establish limiting conditions on fuel storage to assure sufficient safety margin exists to prevent inadvertent criticality. The spent fuel assemblies are stored entirely underwater in a configuration that has been shown to result in a reactivity of less than or equal to 0.95 under worse case conditions. The spent fuel assembly enrichment requirements ln this LCO are required to ensure inadvertent criticality does not occur in the spent fuel pool. Inadvertent criticality within the fuel storage area could result in offsite radiation doses exceeding 10 CFR 50.67 limits.
LCO 3.1.3.2 requires that when LCO 3.1.3.1 is not met, "immediately" initiate action to move the noncomplying fuel assembly to an acceptable configuration. "Immediately'' as used in this completion time means the required action should be pursued without delay and in a controlled manner, to reestablish the safety margins to prevent an inadvertent criticality.
3/4-7 Amendment No. 297
 
::::)
      .w
: a.  =--*
        ~. =---*    ACCE'PTABL DOM~IN BUR~UP i      ...
      -~      --*
      '-I ,... ,...                        UNACCEPTABLE BUANUP DO.MAIN 0
INIT.IAL eRICH"'ENT
* WT . U-235 Figure 3.1.3-1 Minimum Bumup Requirements for Fuel in Region II of the Pool A Storage Racks 3/4-8 Amendment No. 297
 
2.s.----r---,---~------.----.----
:)
  ~
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  ~
ACCEPTABLE BURNUP
* DOMAIN
  !g    1-. 5 LI.I
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0.5 UNACCEPTABLE IURNUP DOMAIN 0.0+.-,-,~t-r-rr'T""i-T"'T"T""T"-i-r--r-rT+....,..._-h,__,_l,...,..._...J 4.J      .4    4.6    4.~      4.7      4.8      4.9        5.0 INITIAL ~ICH'1ENT. wL**U-235 Figure 3.1.3-2 Minimum Bumup Requirements for Fuel in the Pool B Storage Racks 3/4-9 Amendment No. 297
 
200 Exelon Way Exelon Generation~                                              Kennett Square, PA 19348 www.exeloncorp.com TS 5.5.10.d April 13, 2021 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555 Peach Bottom Atomic Power Station, Units 2 and 3 Subsequent Renewed Facility Operating License Nos. DPR-44 and DPR-56 NRC Docket Nos. 50-277 and 50-278
 
==Subject:==
Submittal of Changes to Technical Specifications Bases In accordance with the requirements of Peach Bottom Atomic Power station (PBAPS),
Units 2 and-3, Technical Specification 5.5.1 0.d, Exelon Generation Company, LLC, hereby submits a complete updated copy of the Unit 2 and Unit 3 Technical Specifications Bases.
The enclosed Bases include changes implemented through the date of this letter.
If you have any questions or require further information, please contact Richard Gropp at 610-765-5557.
Respectfully, David P. Helker Sr. Manager, Licensing Exelon Generation Company, LLC
 
==Enclosures:==
: 1) PBAPS Unit 2 Technical Specifications Bases
: 2) PBAPS Unit 3 Technical Specifications Bases cc:    w/o Enclosures                      _
USNRC Region I, Regional Administrator USNRC Senior Resident Inspector, PBAPS USNRC Project Manager, PBAPS                _
W. DeHaas, Pennsylvania Bureau of Radiation Protection S. Seaman, state of Maryland
 
PBAPS Unit 2 Technical Specifications Bases
 
PBAPS Unit 3 Technical Specifications Bases
 
PBAPS UNIT 2 - LfCENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* B        TABLE OF CONTENTS page(a)  i ***-............................................................. , ............................................. Rev 146 II ..*...**....*.._..................... ,...........................................*.*.........................* Rev 145' IH ............................................................................................................Rev 1,50 B 2.0    SAFETY LIMITS (SL&)
page(s)  2.0-1 ....................................................................................................... Rev 157 2.0-2 ..........*; ........................................................................................... Rev 1'57
                      ,2.0-3 .........*........_.............................., .*....... ,... , ......................-,, .........*. , .... Rev 157
                      ~.0-4 .............................*. ,........................................ - ............................. Rev 157 2.0-5 *......*......-................................................. , ....... , .*... ,..*.*......*.. ,..**... ,, ... Rev 75 2.0-6 ......................................................................,. ................................ Rev 128 2.0-7 ...........................................,............................................................. Rev 75 2.0-8 .......................................................................................................,Rev 148 2.0-9 ............................................................................, ....................... ,.... Rev 75 2.0-10 ..................................................................................................... Rev 148 B 3.0    LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY page(s)  3.0-1,. ......................................................................................................Re\t 156 3.0-2 ...............................................-............ , ...........................................,Rev 152 3.0-3 ..................................... , .................. .,. .............................................'Rev 152 3.0-4 ..............................................................................................., ....... Rev 141 3.0-6 **********************************************************-*******************************************Rev' 141 3.0-Sa .....................................................................................................,Rev 141 3.0-Sb. .....................................................................................................Rev 141 3.M ......................................................................................................... Rev 52, 3.0-7 ..........*........*.*..*.............., ..*. , .....*..*...*.*.. ,...............*.......*.....*.......... Rev 141 3.0-7a ..................................................................................................... Rev 141 3.0-9 ............................................................................................, .....*..,.Rav 146 3.0-9a .......... , .............*...*......................................................*................. Rev 145 3.0~9b ................. , ......*......, .............. ,, ..... ,........................_.....**.....*.... , **... Rev 156 3.0-9c, .......*...*.... ;......... , .......................................................................... Rev 156 3,0-9d ,...........* , ............................................... - ...................................... Rev 156 3.0-9e ..................................................................................................... Rev 156 3.0-10 .....................................................: ............................................... Rev 140 3.0-12 ..................................................................................................... Rev, 141 3.0-13 ......................................................................., ............................. Rev 141 3.0-13a ., ................................................................................................. Rev 141 3.0~14 ....................................................................................................... Rev 52 3.0-15 .....................................................................................,.,. ..... ._. ....... Rev 52 B 3.1  . REACTIVITY CONTROL SYSTEMS page(s)  3.1-6 ................................................., .*..........*...*.., *.*..........*..*..*....... ,., ...*. Rev 72 3.1-6,, ....................................................................................................... Re'( 72 3.1-7 ............................................... ,................ ,.............................*.......*.. Rev 72' 3.1-8 ....................................................................................................... Rev 11'3 3.1..S .................................................................,................................., ... Rev t13 3.1-10 ......... ,.. ............................., .............................................................. Rev ,94 3.1-11 ..........................................................., ....... , ................................. Rev 113 3.1-14 ................................................................, ...................................... Rev 49 3.1-16 ........ , ..........*.*...........................*.... , ...... , ........................................... Rev 2 3.1-16 ............... ,........... , ................................................,.,.,.,.................... Rev 79 3.1-17 ... ,., .* ,............. , ............... ,........... , ... , ......... , ......... , .... ,...................... ~R~v 63 PBAPS UNIT2                                                                                                                      Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHN.ICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* B3.1    REACTIVITY COITTROL, SYSTEMS (continued) page(s)  :t1-18 ............. ~ ......................................................................................... Rev 63 a.1-19 ........................................... - .......................................................... Rev 86 3.1-20 ....................................................................................................... Rev 79 3.1-2.1 ....................................................................................................... Rev 63 3.1-23 ....................................................................................................... Rev 49 3.1-25 ....................................................................................................... Rev 57 3.1-26 .................................................................., .................................... Rev 86 3.1-27 ......................................................................................................:Rev 57 3.1*-28 ...................... , ................................................................................ Rev 72 3.1-29 ....................................................................................................... Rev 49 3.1-31 ........................................................................................................Rev 2 3.1-32 .........................................................................................................Rev 2 3.1-33 ...................................................................................................... Rev 88 3.1-34 .......................................................: ............................................... Rev 75 3.1-35 ..................................................................................................... Rev 114 3.1-35a ......... , ........................................................................................... Rev 63 3.1-36 ....................................................................................................... Rev 63 3.1-37 ........................................................_............................................... Rev 86 3.1-38 ........................-............................................................................... Rev 61 3.1-39 ..........................................: .......................................................... Rev 114 3.1-40 ..................................................................................................... Rev 114 3.1-41 .....................................................................................................Rev 114 3.1-42 ..................................................................................................... Rev 114 3.1-43 ........................................................................................., ........... Rev t14 3.1-44 ..................................................................................................... Rev 114 3.1-45 ..................................................................................................... Rev 114 3.1-46* ..................................................................................................,.. Rev 140 3.1-47 ...........................................................................,., ....................... Rev 130 3.1-48 ....................................................................................................... Rev 76*
3.1-49 ,, ......................................................................................., ............. Rev 57 3.1-50 ........................................................................................,.,., .......... Rev 57 3.1-51 ............................, .......................................................................... Rev 86 3.1-62 .........................................................:............................................. Rev,86 B 3.2    POWER DISTRIBUTION LIMITS page(a)  3.2-1 .................... , ............. , .. , .................................................................... Rev 49 3.2-2 ..................................-....................................................................... Rev 49 3.2-3 ..................... , ................................................................................. Rev 143 3.2-4 ........... ,..............................................................._.......................... Rev 143 3.2-6 ......................................................., .. , ............................................ Rev 143 3.2-6 ............................., ......................................................................... Rev 157 3.2-7 ............. , .......... ,, ...........................................................,................. Rev 157 3.2-8 ..............................., ...., .................................................................. Rev 143 3.2-9 ....................................................................................................... Rev 143 3:2-10 ..................................................................................................... Rev 143
                  - 3.2-11 ........ , ............................................., .............................................. Rev 101 3.2-12 ......................................................................................., .* , .......... Rev 143 3.2-12a ......... , .................................................................,., ..................... Rev 143 3.2-13 .......... , ................. ,... ,.................................................................... Rev 143 3~2*13a .................................................................................................. Rev.143
* PBAPS UNIT2                                                    II                                                        Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING .
* 83.3    INSTRUMENTATION page{s)  3.3-1 ....................... ,.................................................................. _........... Rev 134 3.3 6 (ihclusive) ....................................................., ............................ Rev 24 3.3-7 ................................................, ...................................................... Rev 124 3.3-8 ...................................................,................................................... Rev 143 3.3-9 ..............................................................................................'.......... Rev 143 3.3-10 .............................................................................- ........................ Rev 36 3.3-11 ....................................................................................................... Rev 36*
3.3-1.2 ........................................................................................................ Rev* 50 3.3-12a ...................................................................................................Rev 143 3.3-12b ....................................................................................................Rev 143 3.3-12c ........., ......................................................................................... Rev 123 3.3-1.7 ,........, ............................................................................................. Rev 87 3.3-18 .., ................................... :........ ,.....................................................Rev 143 3.3-19 ..................................................................................................... Rev 143 3.3-20 ..................................................................................................... Rev 134
                  ,3.3-21 .....................................................................................................R~v 134
                  '3.3~23 .....................................................................................................Rev 149 3.3-23a ....................................................................................................Rev 149 3.3-24 .........................................., .............................................................. Rev 50 3.. 3-26 .......................................................................................................Rev ,50 3.3-26 ....................,..................................................................................Rev 36 3.3-27 ............................................................................................, ........ Rev 123 3.3-27a .....................................................................;............................. Rev 123 3.3-27b ................................... - .............................................................. Rev 143 3.3-28 ................................. ,.................................., ................................. Rev 149 3.3-28a ...................., .............................................................................. Rev 149 3.3-29 ......................... ,........................................................................... Rev 143 3.3-30 .....................................................................................................Rev 114 3.3-=-31-.:.:... :.. :............... :.:...... :........... :... ;..... :... ~ ...*.. :.. :.................... :*.. :: ... Rev 114.
3.3-32 .....................................................................................................Rev 114 3.3-33 ., *.., ......................... ,...................................................................... Rev 152 3.3-34 ................................................ *-**-****-** .. ******* ..............~ ............... Rev 143 3.3-36 ..................................................................................................... Rev 123 3.3'-36a ...................................................................................................Rev 1'23 3.3-35b .......................................... ,....... ,................................................ Rev 143 3.3 40 (incluslve) .............................................................................. Rev 24 3.3-41 ........ ,........ ,.......................... ,.,, ........................................................ Rev 86 3.3-42 ..................................................................., .* ,................................ R~v 86 3.3-43 .................................... ,.............................................,...........***....*. Rev 86 3.3-44 .........................................................,............................................. Rev 86 3.3-45 .......................................................................................................Rev 36 3.3-46, ............. ,........ ,........., ...................................................................... Rev 36 3.3-48 ... ,. ................................................................................................ Rev 143 3.3-49 .... ,......................,': ...........................................,......................... ~ ..... Rev 63 3.3-52 ............... ,....... ,............................................................................... Rev 86 3.3-53 ....................................................................................................... Rev 86 3.3-54 ..................... ,................................................................................. Rev 86 3.3-65 .............. .,., ....................... ,........... ,.......... ,****.... ,..................., ......... Rev 86 3.3-56 ............................ ,.. ,..**..*.*..., .......................................................... Rev 86 3.3-57 ....................,.............. ,.........................................,......................... Rev 61
* PBAPSUNIT2                                                  Ill                                                            Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING 8 3.3    INSTRUMENTATION (continued) page(s) 3.3-68 ****************************************************************************************-***********Rev 146 3.3-59 *********************************-**************************************.. ******** .................. Rev 143 3.3-60 ..................................................................................................... Rev 143 3.3-62 ...............................................................................................:..... Rev 143 3.UJ ............................................................... ,.......................................,Rev ,86 3,.3-64 ..................................................................................................... Rev 143 3.3-67 .........................................................................................................Rev 7 3.3-68 .........................................................................................................Rev 3 3.3-69 ....... ,........................................... ,,, ................................., ............... Rev 57 3.3-70' .......................................................................................................Rev 55' 3.3-71 .......................................................... ,............ ,............................... Rev 52 3.3-72 .........................................................................................................Rev 3 3.3-73 .............................................................................,........................... Rev 3 3.3-74 .......................................................................................................Rev 86 3.3-75 *..... ,.. ,............................................................................., ............... Rev 86 3.3-76, ...........................................-................................ ,......................... ~ev 132, 3.3-17 .....................................................................................................Rev 132 3.3-78 ....................................................................................................... Rev 52 3,.3-79 ....................................................................................., ............... Rev, 132 3.3-80........-. ............................................,................................... ~ev 132 3.3-81' ........... , ..*. ,,..................,. ............. ., ............. , .........*............,..Rev 132 3.3-82 ..................................................................................................... Rev 132 3.3-83 ..........................,............................................ ,............................. Rev 115 3.3-89 .....................................................................,.................................Rev '86 3.3-90 .......................................................................................................Rev 86 3.3-91 .......................................................................................................Rev 86 3.3-91 a ................................................................................................... Rev 137 3.3-91b ................................................................................................... Rev 143 3.3-91 c ..................................................................................................... Rev 49 3.3-91'd .......................................................................-_.......................... Rev 143 3.3-91 e ................................................................................................... Re:v 143
                    ~.3-91f ...................................................................................................... Rev 57 3.3-91g ................................................................................................... Rev 143 3.3-91 h ...., ................................................................................................ Rev 86 3.3-911 ................................................................................................... Rev 143 3.3-91j ............................................................-*********-********* ... *............... Rev 143 3.3-98, ..................................................................................,.......*.. ,......... Rev 21 3.3-99 .......................................................,............................................. Rev 146 3.3-100 .............. ,....... ,............................................................................ Rev 145 3.3-101 ...................................................................................................Rev 145 3.3-102 ................................................................................................... Rev 145 3.3-103 ................................................................................................... Rev '146 3.3-104 ...........................,..................................................., ................... Rev 146 3.3-106 ................................................................................................... Rev 145 3.3-111 .....................................................................................................Rev 78 3.3-117 ................................................................................................... Rev 146 3.3-118 ......................................................,............................................,Rev 145 3.3-120 ............................................... ~ .................................................. Rev 146 3.3-122 ........................................................:........................................ ,.Rev 146 3.3-124 ..................................................................................................... Rev 68 3.3-125 ..................................................................................................... Rev 83 3'.3-127 ............ ,........................................................................................ Rev 86
* PBAPS UNIT2                                              Iv                                                        Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* B3.3    INSTRUMENTA tlON (continued) page(s)  3.3-128 ..................................................................................................... Rev 86 3.3-129 ................................. ,................................................................... Rev 86 3.3-138 ........................................................................................,.........**. Rev 86 3.3-139 ..................................................................................................... Rev 86 3.3-140 .....................................................................................................Rev 86 3.3-140a ................................................................................................,R,v 145 3.3-140b .................................................................................................,Rev 145 3.3-140c ................................................................................................. Rev 145 3.3-140d ........................................... ,.....................................................,Rev 14$
3.3-140e ................................................................................................. Rev 145 3.3-1401: .................................................................................................. Rev 145 3.3-140g ................................................................................................. Rev 145 3.3-140h ................................................................................................. Rev 145 3.3-140I .................................................................................................. Rev 145 3.3-140J .................................................................................................. Rev 145 3.3-141 ........................................................,.......................................... Rev 134 3.3-142 .....................................................................................................Rev 48 3.3-143 ..................................................................................................... Rev 48 3.3-144 ........... :....................................., ................................................... Rev 67 3.3-145 ..................................... - ....................................................*-*******Rev 67 3.3-147 ................................................................................................... Rev 143 3.3-148 ....................... ,........... ,............................................................... Rev 134 3.3-149 ................................................................................................... Rev 134 3.3-1498 ........ ,.......................................................................................... Rev 75 3.3-150 ................................, ..................................................................,. Rev 76 3.3-161 ..................................................................................................... Rev, 20 3.3-155 ,. ....................................................................................................Rev _32 3.3-156 ..................................................................................................... Rev 75 3.3-157 ...................................................................................................Rev 136 3.3-158 .........., .......... ,...... ,, ... ,.................., .............................................. Rev 145 3'.3,-159 ...................................................................................................Rev 145 3.3-159a ...................................................................................................Rev 57 3.3-160 ..................................................................................................... Rev 57 ,
3.3-161 ............................................*-****** ................................................ Rev 48 3.3-162 ..................... _........................................................................,, ...* Rev 45 3.3-165 ...................... ,............. , ................................................................ Rev 86 3.3-166 ,.................... - ............................................................................Rev 134 3.3-167 ................................................................................................... Rev 114 3.3-168 ...................................................................................................Rev 143 3.3-169-171 (inclusive) ..................................... ,............. ,....................... Rev 1 3.3-172 ....... ,........................................................,...................... ,.. ,........ Rev 140, 3.3-173, .............. ,........................................................................................ Rev 1 3.3-174 ................................................................................................... Rev 145 3.3-175 .......................................................................................................Rev 1 3.3-176 ......................................................................................................,Rev 1 3.3-1'TT ., ...............................................................,., ................................. Rev 86 3.3-178 ......... ,........................................................................................... Rev 86 3.3-179-181 (Inclusive) ........................................................................:... Rev 1 3.3-182 ...................................................................,............................... Rev 145 3.3-183 ........................................................,.......... ,, .................................. Rev' 1 3.3-1'84 .......................................................................,............................. Rev 86 3.3-1'85 ..................................................................................................... Rev '86 PBAPS UNIT2                                              V                                                          Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TE CHNICAL SPECIFICATIONS BASES 1
PAGE REVISION LISTING B3.3    INSTRUMENTATION (continued) page(s)  3.3-186 ..................................................................................................... Rev 86 3.3-187 .................................................................. ,......*...........*... , ............. Rev 6 3.3-188 ................*....*.................*. , ...................*......*..... ,........................ .,Rev 88 3.3-189 ....................... , .. , ..*...........*. ,........................................................ Rev 88 3.3-190 .................................................................................................... Rev 88 3.3-191 - 194 (lnch.1stve) ............................................................................ Rev 6 3.3-195 ................................................................................................., ..* Rev 77 3.3-196 ....................................................................................................... Rev 6 3.3-1,97' ..................................................................................................... Rev 86 3.3-198 ..................................................................................................... Rev 86 3.3-199 ....................................................................................................... Rev 1 3.3-200 .......................................... .-............*............ ,.................................. Rev 1 3.3-201 ............................................. .'......................................................... Rev 1 3.3-202 ....................................................................................................... Rev 1 3.3-203 ........ ,.................................................... , ....................................... Rev 66' 3.3-204 ..................................................................................................... Rev 86 3.3-206 .................................................................................................._... Rev 86 a 3A    REACTOR COOLANT SYSTEM (RCS) page(s)  3.4-1 ..................................................... ~************** ................................. .,Rev 137 3.4-2 .......................................................................... ,............................ Rev 137 3.4-3,...................................................................................................... .,Rev 123 3,4-4 ... , ..................................................................................................... Rev 50 3,.4-5 ....................................................................................................... Rev 123 3.4-6 .........................................................................................................Rev 60 3.4-7 ....................................................... :................. , .................. ,.......... Rev 123 3.4-8 ,.......*.........*..................................................................................... Rev 1'23 3.4-9 ....................................................................................................... Rev 123 3.4-10 .............................................................. - ... , ................................. Rev 123 3.4-14 ........................................... , .................,................., ......... , ............ Rev 143 3.4-15 ..................................................................................................... Rev 114 3.4-16 .............................. , .*...*........ ,....................................................... Rev 148 3.4-16a ................................................................................................... Rev 142 3.4-17 ................................................................. ,................................... Rev 140 3.4-18 ..................................................................... ,............................... Rev 148 3.4-23 ....... , ............................................................................................. ,.Rev 86 3.4-24 ..........................................................................*............................ Rev 93 3.4-25 ....................................................................................................... Rev 93 3.4-26 *......... , ............................................................................................ Rev 93 3.4-26a .................................................................................................. .'Rev 152 3.4-27 .............*...... ,............................. , ........................... ,........................ Rev 86
                  ,3.4-28 ..................................................................................... ,*..*.*..*..*..*.. Rev 93 3.4-29 ............................................ ,.......*..... , ...... ,..................................... Rev 75,
                  ,3.4-30 ....................................................................................................... Rev 76 3.4-31 ......................................... , .......................................................... , .. Rev 76 S.4-32 ....................................................................................................... Rev 86 3.4-34 ..................................................................................................... Rev 126 3.4-36 ....................................................................................................... Rev 52 3.4-37 ..................................................................................................... Rev 126 3.4-37a ................................................................................................... Rev 127 3.4-37b ...... ,.......................... , ............................... , ................................. Rev 126 PBAPS UNIT2                                                vi                                                        Revision No. 157
 
PBAPS UNIT 2 - LICENSE .NO. DPR-44 TECHNICAL SPECI.FICATIONS BASES PAGE REVISION LISTING
* B 3.4    REACTOR COOLANT SYSTEM (RCS) (continued) page(s)  3.4-39 ..................................................................................................... Rev 126*
3.4-42 ........................................ ,,., .....*.....................*..... ,...........*.. ,*........ Rev 127 S.4-42a .........................*........*............*..................................*...............* Rev 126 3.4-43 ......*.............................................................................................* Rev 102 3.4-44 .....................................................................................................Rev 102 3.4-45 ................................................................ :.........................*.*........ Rev 102 3.4-46 ................................................*......................*............................. Rev 102' 3.4-47 ..................................................................................................... Rev 102*
3.4-48 ....*..................................*.............*..........*................................*.*. Rev 102 3*.4-49 ..............................................................................*******~**************Rev 102 3.4-50 ..................................................................................................... Rev 102 3.4-51 ..................................................................................................... Rev 102
                    *3.4-52 ....................................................................................................... Rev 49 3.4-53 ................... ,.......*..................................*........................*............. Rev 114 8 3.5    EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM page(s)  3.5-1 .........................*.......................................................................*..... Rev 145 3*.5-3 .............................*....*..............................*..................*.................. Rev 110 3.6-4 ....................................................................................................... Rev 147 3.5-5 ........................................................................................................ Rev 126 3.5-6 ....................................................................................................... Rev 146 3.5-6a ............ ,..............*........................................................................... Rev 96 3.5-7 ......................................................................................................... Rev 89 3.5-8 ........*............*.......................... ,............................... ,.............*........ Rev 101 3.5-9 ....................................................................................................... Rev 126 3*.S-10 ............................*..........*............................................................. Rev 127 3.6-10a .......................................... , ...................................................~ .... Rev 126 3.5-11 ............*................................................................................ , ......... Rev 86 3.5-t2 ........... ,... ,.....*... ,...... ,.................... ,.........*........ ,............*............... Rev 140 3.5-13 ........................ ,....*...** ,................................................................... Rev 99 3.5-14 ....................................... ,..... ,...................................................... ;Rev 143 3.5-15 ....................................................................................................... Rev 86 3.5-16 ............................ :..............................*.................................. , ........ Rev 86 3.6-17 ..........................................*......................*................................... Rev 101 3.5-18 ..................................................................................................... Rev 145 3.5-19 ............................*...........................*.......... ,.. ,......... ,........*........... Rev 146 3.5-19a- 23 (Oeleted) ............................................................................ Rev 145 3.5-24 ......... ,........*.......................................*.. ,.........*............................. Rev 145 3.6-25 ......*.*.*.......................................................................................... Rev 145 3,5-26 ... ,................................ ,................................................ ,................. Rev 66 3;6-27 .................................................................................................. ,,. Rev 127 3.5-27a ..........*.... ,*..........................................................................**.**... Rev 126 3.5-28 .......*........................................................................ ,........ ,....*...... Rev 143*
3.5-29 ............................................................*.................. ,..........*.*. :........ Rev 86 3.6-30 ......................... ,........... ,...*.....*.*..................................................... Rev 66 3.6-31 .....*............................................................................................... Rev 1*45 3.5-32 ************************-******************************************;**********************************Rev 145 3.5-32a ..........*......*.................................... _. ............................................ Rev 145*
3;5-33 ..................................................................................................... Rev 146 3*.5-34 .............*..*.................................................................................... Rev 146 3.5-35 .................................................................................... , *...*........... Rev 145 3.5-36............. ,................................................................................*....... Rev 145 PBAPS UNIT2                                                vii                                                        Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* B3.6    EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSil:M (continued) page(s)  3.5-37 ..................................................................................................... Rev 145 3.5-38, .. , ....................................................,, ...... , ..................................... Rev 145 3.5-39 ..................................................................................................... Rev 145 B 3.6    CONTAl NM ENT SYSTEMS page(t,)  3.6-1 ............................................................. ,.................................... ,...... Rev Z'l 3.6-2 ....................................................................................................... Re'I 114 3.6-3 ......................................................................................................... Rev 66, 3.6-4 .......................................................................................................,. Rev 86 3.6-5 ....................................................................................................... Rev 118 3.6-7 ............................................ ,.......................................................... Rev 114 3.6-11 ......................................................................................................... Rev 6 3.6-12 ....................................................................................................... Rev 86 3.6-13 ..................................................................................................... Rev 114 3.6-16, ....................................................................................................... Rev 91 3.6-17' ..................................................................................................... Rev 144, 3.6-18 ......................................................................................... ,...*., ..... .,Rev 146
                    '3.6-20 ....................................................................................................... Rev 67 3.6-21 ....................................................................................................... Rev 57 3.6-22 ................ ,...................................................................................... Rev 57 3.6-23 ..................................................................................................... Rev 144 3.6-23a ................................................................................................... Rev 145
* 3.6-24 ....................................................................................................... Rev 91 3.6-25 .......................................... ,............................................................ RQV 86 3.6-26 ....................................................................................................... Rev 86 3.6-27 ..................................................................................................... Rev 140 3.6-28 ......... ,..*..... ,..................................... ,.............................................. Rev 86 3.6-28a ................................................................................................... Rev 1'52 3.6-29 ............................ ,......, ............. , ...............-..................................... Rev 144 3.6-38 ... ,..... ,.......................................................... ,........ , ................ ,..... Rev 114 3.6-31 ....................................................................................................,.Rev 18 3.6-33 ...................... :............................................................................. Rev 114 3.6-35 ...................................................................................................... Rev 91 3.6-38 ...................................................................................................... Rev 66 3.6-39 ............ ,............. ,....* ,............................................. ,....................... Rev 91 3.6--40 ....................................................................................................... Rev 86 3.6-41 ....................................................................................................... Rev 86 3.6-43 ....................................................................................................... Rev 44 3,6-45 .......................................................................................................Rev 66 3.6-46 .......... ,........................................._....*.. ,... ,........ ,....... ,............. c ........ Rev 86 3.6-47 ....................................................................................................... Rev 86 3.6 61 (inclusive)' .............................................................................. Rev 24 3.6-52 ...........-.................... ,................................_..................................... Rev 1,14 3.6-54 ..................................................................................................... Rev 145 3.6-55 ....* ,................................................................................................. 'Rev 86
                    '3.6-56 ,..................................................................................................... Rev 114 3.6-57 ..................................................................................................... Rev 126 3.6-58 ..................................................................................................... Rev 1'51 3.6-59 .,., ............................................. ,................................................... Rev 140
* PBAPS UNIT2                                                viii                                                        Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* B 3.6    CONTAINMENT SYSTEMS (continued) pege(s)  '3.6-59a ............................................................................................: ...... Rev 1'27 3.6-59b ...................................................................., .............................. Rev 126 3.6-60 ................. ; ................................................................................... Rev 114 3.6-61 ......................................... - .......................................................... Rev 126 3.6-62 ....................................................................................................-.Rev 151 3.6-63 .............................. .._ ..................................................................... Rev 130 3.6-63a ........................................................................................,..*....... Rev' 127 3.6-63b ........... , ..... , .. **********************************************-****.. *************** .. ******** Rev 126 3 . ~ ............................... *-*** .......... - .................................................. Rev 126 3;6-63d ................................................................................................... Rev 126 3.6-63e ................................................................................................... Rev 151 3:6-63f .................................................................................................... Rev 130 3.6-63g ................................................................................................... Rev 127 3.6-63h ..................................................................................; ................ Rev 126
                    ,3.6-64 .......................................................................................................Rev 80 3.6-70 ....................................................................................................... Rev 80 3.6-72 ....................................................................................................... Rev 86 3.6-73 ...........................................; ........................................................... Rev 75 3.6-74 .....................................................................................................Rev '145 3.6-75 ......................................................., ......................._...................... Rev 146 3;6-76 .................................... , ................................................................ Rev 120 3.6-TT .......................................................................................................,Rev 97 3.6-78,. ......................................................................................- .............. Rev 75' 3.6-79, .....................................................................................................Rev 145 3.6-81 ...................... ,......................................................., ........................ Rev 57 3.6-82 .............................................................................., ...................... Rev 145 3.6-83 .....................................................................................................Rev 140 3.6-84 ................................................................................., .............*....... Rev '86 3.6-87 .....................................................................................................Rev 145 3.6-88 ......................................................................,.............................. Rev 145 3.6-89 ............. , ....................................................................................... Rev 146 3.6-90 .......................................................................................................Rev 86 B 3.7    PLANT SYSTEMS page(s) . 3.7-1, .......................................................................................................Rev 114 3.7-2 .......................................................................................................Rev 114 3.7-3 .......................................................................................................Rev 144 3.7-4 .......................... , ....................., .. - ............. :....................................,Rev 151 3.7-5 ................................., ..................................................................... Rev 151 3.7-Sa ............................................... ,..................................................... Rev 114 3.7-Sb ........... ,. ..................................................................,..................... Rev 114, 3,.7-6 .......................... _... -.......................................................................__ .*. Rev 4 3.7-1 ....................................................................................................... Rev 109 3.7-8 .............. , ........................................................................................ R~v 1,09' 3.7-9 ....... , ...................................... , ...... , ................................................. Rev 109
: 3. 7-1,0 .......................................................................................................Rev 86 3.7-11 ., .............., ..-..... , ..............................................................................Rev 67 3.7-12 .......................................................................................................Rev 92 3.7-13 ........... , .............................................................................................,Rev 1
* PBAPS UNIT2                                                  , ix                                                        Revision No. 157
 
PBAPS UNIT 2 - LICENS'E NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* B 3.7  PLANT SYSTEMS (continued) page(s)  3,7~14 ....................................................................................................... Rev 86 3.7-15 ..................................................................................................... Rev 118 3.7-16 ..................................................................................................... Rev 116 3.7-18a ................................................................................................... Rev 1'18 3.7-16b .................................................................................................. ,Rev 121 3.7-17 ..................................................................................................... Rev 146 3.7-18 ................................................ ,......................................... ,., ........ Rev 116 3.7-19 ..................................................................................................... 'Rev 145 3.7-20 ..................................................................................................... Rev 145 3.7-20a ................................................................................................... Rev 116 3,7-21 ..................................................................................................... Rev 121, 3.7-23 ......................................... ,......... ,.................................... ,.............. Rev 66 3.7-24 ....................................................................................................... Rev 88 3.7-26 ..................................................................................................... Rev 143 3.7-26 ..................................................................................................... Rev' 143 3.7-27 ..................................................................................................... Rev 143 3.7-28 ..............................................................,, .......... , .......................... Rev 143 3.7-29 ....................................................................................................... Rev 75
                  ,3.1-30 ....................................................................................................... Rev 86 B -3.8  ELECTRICAL POWl:R SYSTEMS page(~) 3.&-1 ......................................................................................................... Rev 82 3.8-2 ..................................................... :, .. ,........... ,...* ,.............................. Rev 90 3.8-2a ....................................................................................................... Rev 90 3.'8-3 ....................................................................................................... Rev 114 3.8-6 ......................................................................................................... R'ev 73 3.8'-6' ...... , ....................................................................., ............ ; ............... Rev 52 3.8-7 ................................................... , .................................... *-****************Rev 5 3.8-8 ....................... ,................................................................................. Rev 85 3.8-9 ......................................................................................................... Rev: 86 3.8'-10 ......................................................................................................... Rev 5 3.8.i11 ........................................................................................... :........... Rev 60 3.8-12 ......................................................................................................... Rev 1 3.8..17 ................................................. ,....................... ,............................. Rev 86 3.8-18 .............. ,, ............................... ,,, ..................................................... Rev 71 3.8-19 ............................................................. ,............................... ,......... Rev 86 3:8-20 ............................. ,......................................................................... Rev' 86 3.8-21 ................................................................................ 0 ...................... Rev 88 3.8-22 ....................................................................................................... Rev 86 3.8-23 ....................................................................................................... Rev 86 3.8-24, ..................................................................................................... Rev 139 3.8-26 ......................................................................................................... Rev 1 3.8-26 .*. ,, .................................................................................................. Rev' 86 3.8-27 .......................................................... ,............................................ Rev 86 3.8-27a ...................................................................................................... Rev 67 3.8-28 ............... ,....................................................................................... Rev 86 3.8-29 ....................................................................................................... Rev 71 3.8-30 ....................................................................................................... Rev 86 3.8-31 ........................................................, .............................................. 'Rev 67
* PBAPSUNIT2                                                  X                                                        Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION' LISTING
* B3.8    ELECTRICAL POWER SYSTEM$ (corttinued) page(s) 3.8-32 ................................................................. :..................................... Rev 86 3.8-33 ................................................................................ 1...................... Rev 86 3.8-34 ....................................................... ,............................................... Rev 86 3.8-35 ..................................................................................................... Rev 117 3.8-36 ....................................................................................................... Rev ,86, 3'.8-37 ....................................................................................................... Rev 71 3'.8-38 ........-............................................................................... ,............... Rev 86 3.8-39 ................................................................................................. , ..... Rev 95 3.~ ..............................................................................,......*........*..*... Rev' 146
                  ,3.8-42 ........................................................ ,., .. ,................................... ,... Rev 145 3.8-43 ................................. ,................................................................... Rev 146 3.8-44 .............................................................. ,..................... , ............... .,Rev' 14!i 3'.8-45 ..................................................................................................... Rev 145 3.8-46 ................................................................................................... ,.Rev 145 3.8-47 :.......... ,, .......................................................................................-... Rev 16 3.8-48 ........................... ,......................................................................... Rev 106 3.8-49 ..................................................................................................... Rev 122 3.8-61 ........................................................................................, ............ Rev 138 3.8-53 ..................................................................................................... Rev 138 3.8~ ....................................................................................................... Rev 86 3.8-66 ..... ,............................................................................................... Rev 122 3.8-56 ..... ,............................................................................................... Rev 122 3.8-67 ..................................................................................................... Rev 122 3'.8-59 ........................................ ,.................. ,......................................... Rev 160 3.8-60 ........................................................................................ , ............ Rev 160 3.8-60a ....... ,..... ,....... ,...... ,...................................................................... Rev 150 3.8-62 ...................................................-.....-................. ,.......... ,................ R.ev 1'54 3.8-62& ., ................................... ,.................................. :.......................... Rev 153 3.8-62b ......................................................................................... ,......... Rev 163 3.8-63 ....................... ,.............................................................. ,.............. Rev 154 3.8-63a ................................................................................................... Rev 163 3.8-63b .............................................. ,.............. ,... , .... , .......... ,................. RQV 163
                  '3,.8-64 ..................... - .............................................................................. Rev 163 3.8-66 ....................................................... ,, ... ,., ...................................... Rev 165 3.8-66' ..................................................................................................... Rev 150 3.8-67 .......................................... ,...... ,....................... ,........................... Rev 150 3.8-68 ..................................................................................................... Rev '150 3.8-69 ............................... ,..................................................................... Rev 150 3.8-10 ..................................................................................................... Rev 150 3.8-71 ..................................................................................................... Rev 150 3.8-72 ............................................................. - ...................................... Rev 146 3.'8-73 ..................................................................................................... Rev' 145 3.8-74 ..................................................................................................... Rev 150 3.8-75 .................................................................................................... .,Rev 150 3.8-76a ................................................................................................... Rev 160 3.8-76 ..................................................................................................... Rav 150 3.8-TT ..................................................................................................... Rev 160 3.8-TTa ................................................................................................... Rev 150 3.8-78 ..................................................................................................... Rev 150 3.8-78a ................................................................................................... Rev 150 3.8-78b ...................................................................................................,Rev 160 3.~78c ................................................................................................... Rev 1'50
* PBAPS UNIT2                                              xi                                                          Revision No 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* B 3.8    ELEC'FRJCAL POWER SYSTEMS (continued) pages(s) 3.8-79 ..................................................................................................... Rev 156 3.~0 ..................................................................................................... Rev' 160 3.8-81 ..................................................................................................... Rev 160 3.8-82 ..................................................................................................... Rev 150 3.8-85 ..................................................................................................... Rev 150 3.8-89 ....................................................................................................... Rev 85 3.8-90 ....................................................................................................... Rev 85 3.8-91 .................................. ,... ,... ,.. ,........ ,............................................... ,Rev 85 3.8-92 ................................................................................................. ,..... Rev 86 3.8-94 ............................_......................................................................... Rev 146 3.8-95 .................................................................................................. ,.. Rev 146 3.8-96 ................................................................................................ , .... Rev 145 3.8-97 ....................... ,............................................................................. Rev 145 B 3.9    REFUELING OPERATlONS 3.9-1 ......................................................................................................... Rev 29 3.9-3 ...................................... ,.................................................................. Rev 29 3.9-4 .................................................................................................... ,.... Rev 86 3.9-7 ......................................................................................................... Rev 86 3.9-8 ......................................................................................................... Rev 24 3.9-9 ............. ,........................................................................................... Rev 86 3.9-10, ........................................................ ,................................. .'............ Rev 24 3.$-14 ........... , ........................................................................................... Rev 24 3.9-15 ...................................................... , ................................................ Rev 86 3.9-17 ......................................................... ,............................................. Rev 75 3.9-1'9 ....................................................................................................... Rev 86 3.9-21 ..................................................................................................... Rev 126 3.9-23 ........................................................ ,............................................ Rev 1'26 3.9-23a ...................................................... ,............................................ Rev 127 3.9-23b ................................................................................................... Rev 126 3.9-25 .................................................................... ,................................ REJV 126 3.9-27 ......................................................... :........................................ ,.. Rev 126 3.9-28 .............., ...................................................................................... Rev 127 3.9-29 .................................................................................. , .................. Rev 126 B3.10    SPECIAL OPERATIONS page{s)  3.10..1 ....... ,., ..... ,..................................................................................... Rev 129 3.10-2 ..................................................... ,............................................... Rev 1'29 3.10-2a ................................................................................................... Rev 145 3.10-3 .................................................................................................... ,Rev 129 3.10-4 ..................................................................................................... Rev 129 3.10-6 ......................................................................................... ,............. Rev 24 3.10-8 ....................................................... , ............................................... Rev 86 3.10-9 ...............................~ ....................................................................... Rev 86
: 3. 1'0-13 .............................................................................-........................ Rev 86 3.1'0-18 ..................................... ,........................... ,.............. ,.................... Rev 86 3.10-22 ..................................................................................................... Rev 86 3.10-26 ......................................................................................... ,........... Rev 86 PBAPS UNIT2                                                xJj                                                      Revision No. 157
 
PBAPS UNIT 2 .. LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* 133.10      SPECIAL OPERATIONS (continued) page{s)  3.10-30 ....................................:........*.....*........*..*..................................... Rev 3.10-31 ..................................................................................................... Rev 3.10-32 ............................................. :..................................... ,................. Rev 72 24 36 3.10-33 *..*....*............. ,.......................................................................- *..* Rev  63 3.10-35 ..................................................................................................... Rev  86 3.,10-36 .........................................................................., *................*........ Rev 86 All remaining pages are Rev 0 dated 1/18196.
PBAPS UNIT2                                                xiii                                                      Revision No. 157
 
TABLE OF CONTENTS
* B 2.0 B 2.1.1 B 2.1.2 B 3.0 SAFETY LIMITS (SLs) ......................................... B .2.0-1 Reactor Core SLs **.*...*.*.....*..*..*......*.,. .* ,. ,. B 2.0-1 Reactor Cool ant System <RCS) Pre-ssure SL .........*. B 2. 0- 7 LIMITING CONDITION FOR OPERATION (LCD) APPLICABilITY *..*...* B 3.0-1 8 3 ,0      SURVEILLANCE REQUIREMENT CSR) APPLlCABILITY ...... ,*..*.....*. B: 3.0-10 B  3.l            REACTIVITY CONTROL SYSTEMS ...*.............*............ 8 3.1-1 B  3.1.l              SHUTDOWN MARGIN (SOM) ............................... 8 3,1-1 B  3.1,2              Reactivity Anomalies ....... , ............... , *a* . . . . . . B 3.1-8 B  3.1.3              Control Rod OPERABILJTY ........ , .................... B 3.1-13 8 3.1.4                c*ontrol Rod Scram Times ............................. B 3.1-22 B 3.1.5                Contra l Rod Scram Accumulators *.......... "' ......... B 3 .1-29 B 3.1.6                Rod Pattern Control ....., . ,.....*.*..*..........*..... B 3 .1-34 B 3.1.7                Stand:by Liquid Control (SLC) System *......*...*.*.*. B 3.1-39 B 3.. 1.8              Scram Discharge Volume (SDV) Vent and Drain Valves .., B 3.1-48 B 3.2            POWER DISTRIBUTION LIMITS ....................*......**..                B 3.2-1 13 3.2.1              AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APlHGR) ............* ,, .....*..*..***.........*.*            B 3.2-1 B 3 .Z.2              MINIMUM CRITICAL POWER RATIO (MCPR) .., ...............            B 3.2-6 B 3.2 *.3              LINEAR HEAT Gf:NERATION RATE ( LHGR) ., .*...*........*.            B 3. 2"-11 B 3.3            INSTRUMENTATION .*.......*........, .......*...... ,......*.. B 3.3-1 B 3.3.1.l        Reactor Protection System ( RPS) InstrumentaHon ..... ,... ,. B 3.3-1 B 3.3.1.2        Wide Range Neutron MonHor ,(WRNM) Instrumentation *....*. B 3.. 3-36 8 3. 3. 2~ 1-  --*Control ,Rod Klock Instrurne*ntatio-n .. : ..... :: .. *.- ..... ~: **** B 3~3-~45 B 3.3.2. 2c      Feedwater and Main Turbine High Water Level Trip Instrumentation .........*............ , *......*.... B 3.3.-58 B 3.3,3.1        Post Accid,ent Monitoring (PAM) Instrumentation ..*.*..... B 3.3-65 B 3.3.3.2        Remote Sh'utdown System .................................. B 3. 3- 76 B 3.3.4.1        Antic, pated Tra.nsi ent Without Scram Reci rc1.1l ati on Pump Trip (ATWS-RPT) Instrumentation ....*.*...... B 3.3-83 B 3.3.4.2        End 0f Cycle Recirculat1on Pump Trip (EOC-RPT) Instrumentation . . .          8 3.3-91a thru B .3.3-9lj B 3.3.5.1        Emergency Core Co0ling System (EC.CS)
Irrstrume:ntation **.....*.................*......*... B 3.3-92 B 3.3.5.2        Reactor Core 'Isolation Coolii:19 (RCIC) System fnstrumentatiori ..................................... B 3.3-130 B 3.3.5.3        N.ot U*sed .*.......*....**.... ,., *....*............ , *. , .*...*, B-3.3-140a B 3.3.5.4        Reactor Pressure Ves:se1 CRPV) Water Inventory Control Instrumentation ........*......*......*..*.........*.. 8-3.3.140b B 3.3.6.1        Primary Containm~nt Isolation Instrume~tation ....**..... B 3.3-141 B 3.3.6.2        Secondary Containment Iso.7ation InstrumentaUon ... ,, .**. B 3.3.-169 B 3.3.7.l        Main Control Room Emergency Venti1ation (MCREV)
System Instrumentation ........................... B. 3.3-180 B 3.3.8.1        Loss of Power (LOP) InstrLtmentation ...*.....*.....**..*. B 3.3-187 B 3 .. 3.8.2      Reactor Protection System (RPS) Electric Power Monito-r,irig .*..*........*.*.***.*.*.*........ , ...* B 3 .3-199 (Continued)
PBAPS LH{IT Z                                                                Rev~sion No. 145
 
TABLE OF CONTENTS Ccontinu,ed)
* B 3.4 B 3.4.1 B
B B
3.4.2 3.4.3 3.4.4 REACTOR COOLANT SYSTEM (RCS) .*....*....*..*............*
Rec1rcul ati on Loops Opera.ting .*.*..............*..*.
                      .Jet Pumps *.............***..*....*.*..................
Safety Relief Valves (SRVs) and Safety Valves (SVs).
RC$ Ope,rational LtAKAGE .............................
B 3.4-1 B 3 .4-1 B 3.4-11 B 3.4-15 B 3.4-19 B  3.4.5            RCS Leakage Detection Instrumentation *......**..*...                                                B 3.4-24 B  3.4.6            RCS Specific Activity .............................. ,                                              8 3.4-29 B  3.4.7            Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown *.........*..*..............*                                                B 3.4-33 B 3.4.8              Residual Heat Removal (RHR) Shutdown Cooling System-Cold Shutdown ..*.*.*..*....... , ....*.*...                                              B 3 .4-38 B 3.4.9            RCS Pressure at'.ld Temperature (P/T) Limits ..*..... , ..                                            B 3'.4-43 B 3.4.10            Reactor Steam Dume Pressure ..........................                                              B 3. 4-52 B 3.5        EMERGENCY CORE COOU NG SYSTEMS ( ECCS), RPV WATER INVENTORY CONTROL (WIC), AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM .... ,., ............................                                                B  3.5-1 B 3. s*.1          ECCS ......*......*. ,., ...*......*... , **..*..*..*.*.**                                          B  3.5-l B 3.5.2              Deleted ....** ; ......*...*........._.**...**..*.........                                          B  3 *..5-18 B 3.5.3            RCIC System ........... ,., ...........*....**.....*..*                                              B  3.5-24 B 3.5.4            RPV Water Inventory Control .......*.*...............                                                B  3.5-25
  'B  3.6        CONTAINMENT SYSTEMS ................................ , ....                                                B  3.6-1 3.6.1.1    Primary Containment ......................................                                                  B  3.6-1 B
B  3.6.1.2    Primary Containment Air Lock ......*...**..*.....*.......                                                  B  3.6-6 B  3.6.1.3    Primary Containment Isolation Valves (PCIVs) ....... , *.*.                                                B  3.6-14 B  3.6.1.4    Drywell Air Tempera.ture- ............... -. *........-.-.*.. -.-.;                                        B  3;6*31 B  3.6.1.5    Reactor Building-to-Suppression Chamber Vacuum Breakers, .*.......*...........*........*..... ,, ....                                            B  3.6-34 B  3.6.1.6    Suppression Chamber-to-Drywell Vacuum Breakers ..*...*.* ,                                                  B  3.6-42 B  3. 6 :2. 1 Suppression Pool Average Temperature .**...*.*...*.......                                                  B  3.6-48 B  3.6.2.2    Suppression Pool W.ater Level ............................                                                  B  3.6-53 B  3.6.2.3    Resid*ual Heat Removal (RHR) Suppression Pool
( ool i ng . . . . . . . . . . . . . . . . .. . . . . * . . . . . . .. * . , . . . . . . . . . . 8* 3 . 6 -55*
B 3.6.2.4      Residual Heat Removal {RHR) Suppression Pool Spray ......                                                  B  3.6-60 B 3.6.2.5    Residual Heat Removal (RHR) Drywell Spray ...............                                                  B  3.6-63a B 3.6.3.1    Dele,ted ..........*...***.....*........*..*..**..*.......                                                B  3.6-64 8 3.6.3.2    Primary Containment Oxygen Concentration ....*.. , .........                                              B  3.6-70 B 3.6.4.1    Secondary Containment .....*...**...**......*.....**.....                                                  B  3. 6- 73 8 3.6.4.2    Secondary Containment Isolation Va1ves (SCIVs) ..........                                                  B  3.6-78 B 3.6.4.3    Standby Gas Treatment (SGT) System .*.............**.....                                                  B  3.6-85 B 3.7        PLANT SYSTEMS ..*.......*....*.*............**.............                                                B 3. 7 ~l B 3.7.1            High Pressure Service Water (HPSW) System .*.........                                                B 3i7-1 B 3.7.2            Emergency Service Water (ESW) System and Normal Heat Sink ..........*.*.*...*....... , ...*..*....*                                              B 3.7~6
  .B 3.7.3            Emergency Heat Sink .................................                                                B 3.7-11 B 3. 7 .4          Main Control Room Emergency Ventilation CMCREV)
System .........*...* , ....*................*..* .- ...*                                        8 3.7-15 B 3. 7 .. 5          Main Condenser Offgas ......*...*....*.......*.......                                                B 3.7-22 PBAPS UNIT 2                                            ii                                          Revision No. 145
 
TABLE OF CONTENTS (continued) a 3.7        PLAN1 SYSTEMS (continued)
B 3.7.6          Main Turbine Bypass System .......................... B 3. 7-25 B 3.7.7          Spent Fuel Storage Pool Water Leve1 ............. , .... B 3. 7-29 B 3.8        ELECTRICAL POWER SYSTEMS ......* , *...........*........... B 3.8-1 B 3.8.1          AC Sources ~Operatir'rg ................................ B 3. 8-1 B 3.8.2          AC Sources-Shutdown ..................................      B 3. 8-40 B 3.8.3          Diesel Fuel 011, Lube Oil, and Starting Air .*.......        B 3.8-48 B  3.8.4          DC Sources-Operating ........................ , ........ B 3.8-!x3 B  3.8.5          DC Sources-Shutdown .*...*.....................*....      .B 3.8-72 B  3.8 .. 6      Battery Parameters ...*.....................*... , ....      B 3. 8- 77 B  3.8.7        Distribution Systems-Operating., ...*................        B 3.8-83 B  3.8.8          Distribution Systems-Shutdown ......................        B 3.8-94 B 3.9        RE~UELlNG OPERA HONS .....................................      B 3.9-l B 3 .. 9 .1      Refueling Equipment Interlocks.................* , ....      B 3-. 9-1 B 3.9.2          Refuel Position One-Ro'd-Out- Inter1ock ...............      B 3.9-5 B  3.9.3        Contr--01 Rod Position ................................      B 3.9-8 B  3.9.4        Control Rod Posi.tion Indication .....................      B 3.9-10 B  3.9.5        Control Rod OPERABILITY-Refueling ....................      B 3.'9&deg;14 B  3.9.6          Reactor Pressure Vess~~ (RP\/) Water Level ...........      B 3. 9-17 B 3.9.7          Residual Heat Removal (RH'R)-High Water Level .......      B 3.9-20 B 3.9.8          Residual Heat Removal (RHR)-Low Water Level ........        B J.9-24
* B 3 .10 B 3.10.1 B 3 .10-. 2 B 3.10.3 B 3.10.4 SPECIAL OPERAHONS ................*.*...........*.. , , .......
Inservite Leak and Hydrostatic Testing Operation ....
                    ~eattor M~de Swftch Int~~lo~k Teiting ...............
Single Control Rod Withdrawal-Hot Shutdown .........
Single Control Rod Withdrawal-Cold Shutdown ........
8 B
B B
B 3.10-1 3.10~1 3.10-5 3.10-10 3.10&deg;14 B 3.10.5          Single Control Rod Drive (CRD)
Removal-Refueling .................... , .......... B 3.10-19 B 3.10.6        Multiple Control Rod Withdrawal-Refueling ...*........      B 3.10-24 B 3.10.7          Control Rod Testing-Operating ............... , ......      B 3.10-27 l3 3.10.8        SHUTDOWN MARGIN (SOM) Test-Refueling ................      B 3.10-31 PBAPS UNIT 2                            iii                          Revision No. 150
 
Reactor Core SLs B 2.1.1
* B 2.Q B Z.1.1 SAFETY LIMITS (SLs)
Reactor CQre SLs BASES BACKGROUND        SLs ensure that specified acceptable fuel design limits are not exceeded during steady state operation, normal operational transients, and abnormal operational transients.
The fuel cladding integrity SL is set such that no fuel damage is calculated to occur if the limit is not violated.
Because fuel damage is not directly observable, a stepback approach is used to establish an SL, such that 99.9% of the fuel rods avoid transition boiling. Meeting the SL can be demonstrated by analysis that confirms no more than 0.1% of fuel rods in the core are susceptible to transiti.on bo.iling or by demonstrating that the MCPR is not less than the limit specified in Specification 2.1.1.2 for General Electric (GE)
Company fuel . MCPR greater than the specified limit represents a conservative margin relative to the conditions required to maintain fuel cladding integrity.
* The fuel cladding is one of the physical barriers that separate the radioactive materials from the environs. The integrity of this cladding barrier is related to its relative freedom from perforations or cracking.
* Al though some corrosion or use related cracking may otcur during the life of the cladd,ng, fission product migration from this source is incrementally cumulative and continuously measurable. Fuel cladding perforations, however, can result from thermal stresses, which occur from reactor operation significamtly above design conditions.
While fission product migration from claddiny perforation is just as measurable as that from use related cracking, the thermally caused cladding perforations stgna7 a threshold beyond which still greater thermal stresses may cause gross, rather than incremental, cladding deterioration. Therefore, the fuel cladding SL is defined with a margin to the conditions that w~ul d produce onset of transition boiling (i.e., MCPR = 1.00). These conditions represent a significant departure from the condition intended by design for planned operation. This is accompltshed by having a Safety Limit ~inimum Critical Power Ratio (SLMCPR) design basis, referred to as SLMCPR9s195. which corresponds to a 95%
prob a.bi l ity at a 9.5% cohfi dence level ( the 95/95 MCPR criterion) that transition boiling will not occur .
* PBAPS UNIT 2                            B 2.. 0-1                    Revision No. 157
 
Reactor Core SLs B 2.Ll
* BASES BACKGROUND (continued)
Operation above the boundary of the nucleate boiling regime could result in excessive cladding temperature because of the onset of transition boiling and the resultant sharp red~ct1on in heat transfer coefficient. Inside the steam film, high cladding temperatures are reached, and a cladding water (zirconium w.ater) reaction may take place. This chemical reaction results in oxidation of the fuel cladding to a str*ucturally weaker form. This weaker form may lose its integrity, resulting in an uncontrolled rel ease of activity to the reactor coolant.
The reactor vessel water level SL ensures that adequate core cooling capability is maintatned during all MODES of reactor operation. Establishment of Emergency Core Cooling System initiation setpoints higher than this safety limit provides margin such that the safety limit will not be reached or exceeded.
APP LI CABt.E  The fuel cladding must not sustain damage as a result of SAFETY ANALYSES normal operation and abnormal operational transients. The Tech Spec SL is set generic-ally on a fuel product MCPR
* correlation basis as the MCPR which corresponds to a 96%
probability at a 95% confidence level that trans1tion boi 1-i ng wi 11 not occur, referred to as SLMCPR9s19s.
                                                                ~ -
The Reactor Protection System setpoints (LCD 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"), in combination with other lCOs, are designed to prevent any anticipated combination of transient conditions for Reactor Coolant System water level, pressure, and THERMAL POWER level that would result in reaching the MCPR limit.
2,1.1.1      Fuel Cladding Integrity GE critical power correlations are applicable for all critical power calculations at pressures~ 700 psia and core flows ~ 10% of rated fl ow. For operation at low pressures or low flows. another basis is used, as follows:
The pressure drop in the bypass region is essentially all elevation head with a Valu~ > 4.5 psi; therefore, the core pressure drop at low power and flows will always be> 4.5 psi. At power, the static head inside
* PBAPS UNIT 2                          B 2.0-2                    Revision No. 157
 
Reactor Core SLs B 2.Ll
* BASES APP LI CABLE SAFETY ANALYSES 2.1.1,1    Fuel Cladding Integrity (continued) the bundle is less than the static head in the bypass region because the addition of heat reduces the density of the water. At the same time, dynamic head loss in the bundle will be greater than in the bypass region because of two phase flow effects. Analyses show that this combination of effects causes bundle press~re drop to be nearly independent of bundle power when bundle flow is 28 X 10 3 lb/hr and bundle pressure drop is 3.5 psi. Because core pressure drop at low power and flows wi 11 al ways be > 4. 5 psi, the bundle flow will be> 28 X 10 3 lb/hr.
Full scale ATLAS test data taken at pressures from 14.7 psia (0 psig) to 800 psia (785 psig) indicate that the fuel assembly critic.al power with bundle flow at 28 X 10 3 lb/hr is approximately 3.35 MWL This is equivalent to a THERMAC POWER> 50% RTP even when design peaking factors are considered. Therefore, a THERMAL-POWER limit of 22.6% RTP for reactor pressure
                        < 700 psia is conservative. Additional informati0n on
* low flow conditions is available in Reference 4 .
: 2. L 1. 2, ,M_CE:R The fuel cladding integrity SL is set such that no fuel damage is calculated to occur if the limit ts not violated.
Since the parameters that result in fuel damage-are not directly observable during reactor operation, the thermal and hydraulic conditions that result in the onset of transition boi 1 j ng, have been used to mark the beginning of the region in which fuel damage could occur. Although it is recognized that the onset of transition boiling would not result in damage to BWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit. The Technical Specification SL value 'is dependent on the fuel product line and the corresponding MCPR correlation, which is cycle independent.
The value is based on the Critical Power Ration (CPR) data statistics and a 95% probability with 95% confidence that rods are not susceptible to boiling transition, referred to as MCPR9s19s.
The SL is based on GNF2 fuel. For cores with a single fuel product line, the SlMCPR 95195 is the MCPR95;95 for the fuel type. For cores loaded with a mix of applicable fuel types, the SLMCPR 95195 is based an the largest (i.e., most limiting) of the MCPR values for the fuel product lines that are fresh or once-turnt at the start of the cycle.
eontinued PBAP-S UNIT 2                        B 2 .. 0-3                Revision No. )57
 
Rea.ctor Cor'e SLs B 2.1.1
* BASES APPLICABLE SAFETY ANALYSES 2.1.1.3    Reactor Vessel Water Level During MODES 1 ana 2 the reijctor vessel water level is required to be above the top of the active fu~l to provide core cooling capability. With fuel in the reactor vessel during periods when the reactor is shut down, consi d.erati on
* must be gi V'en to water level requ*i rements due to the effect of decay heat. If the water level should drop below the top of the active irradiated fuel during this period, the ability to remove decay heat is reduted. This reduction in cooling capability could lead to elevijted cladding temperatures and clad perforation. The core can be adequately cooled as long as water level is above 2 /3 of the core height. The reactor vessel water level SL has been established at the top of the active irradiated fuel to provide a point that ca.n be monitored and to also provide adequate margin for effective action.
(continued)
* PBAPS UNIT 2                      B 2.0-4                      Revision No. 157
 
Reactor Core Sl...s B 2.1.1
* BASES    (cont1nUed)
SAFETY LIM[TS        The reactor core SLs are establ1shed to protect the jntegr1ty of the fuel clad barr1er to the release of radioact1ve materials to the env1rons. SL 2.1.1.1 and SL 2.1.1.2 ensure that the core operates within the fuel des1gn criteria. SL 2.1.1.3 ensures that the reactor vesse1 water level is greater than the top of the act1ve 1rrad1ated fuel in order to pr~vent elevated clad temperatures and resultant cl ad perforations.
APP LI GABI LilY    SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in all MODES.
SAFETY LIMIT        Exceeding an SL may cause fuel damage and create a potent1al VIOLATIONS          for radioactive releases in excess of 10 Cl=R 100, '!Reactor Site Cr1teria," limits (Ref. 2) and 10 CFR 50.67, uAccident Source Term,~ for accidents analyzed using AST (Ref 3).
Therefore, it is required to insert all insertable control rods and restore compliance with the SLs w1th1n 2 hours. The 2 hour Completion Time ensures that the operators take prompt remedial action and al so ensures that the probability of an accident occurring dur1ng this period is minimal .
(continued)
* PBAPS UNIT 2                          B 2.0-5                    Revision No. 75
 
Reactor Core Sls B 2.1.1
* BASES REFERENCES    1. NEDE-24011-P-A, uGeneral Electric Standard Application for Reactor Fuel," 1 atest approved revision.
: 2. 10 CPR 100.
3* 10 CF R 50 . 67 .
: 4. .SIL No. 516 Supp1ement 2, January 19,. 1996 .
* PBAPS UN IT 2                    B 2.0-6                  Revision No. 128
 
RCS Pressure SL B 2.1.2
* B 2. O SAFETY LIMITS (SLs)
B 2.1.2  Reactor Coolant System (RCS) Pressure SL BASES BACKGROUND        The SL on reactor steam dome pressure protects the RCS against overpressurization. In the event of fuel cladding failure, fission products are released into the reactor coolant. lhe RCS then serves as the primary barrier in preventing the release of fission products into the atmosphere. Esta bl i sh1 ng an upper 11 mi t on reactor steam dome pressure ensures continued RCS integrity with regard to pressure excursions. Per the UFSAR (Ref. 1), the reactor coolant pressure boundary (RCPB) shall be designed with-sufficient margin to ensure that the design conditions are not exceeded duriflg normal operation and abnormal operational transients.
During normal operation and abnormal operational transients, RCS pressure is limited from exceeding the design pressure by more than 10%, in accordance with Section III of the ASME Code (Ref. 2). Tb ensure system integrity, all RCS
* components are hydrostatically tested at 125% of design pressure, in accordance with ASHE Code requirements, prior to initial operation when there is no fuel in the core. Any further hydrostatic testing-with fuel in the core may be done under LCO 3.t0.1, "Inservice Leak and Hydrostatic Testing Operation." Following inception of unit operation, RCS components shall be pressure tested in accordance With the requirements of ASHE Code, Section XI (Ref. 3).
Overpressurization of the RCS could result in a breach of the RCPB reducing the number of protecti vs barri,ers des1 gned to prevent rad1oactive releases from exceeding the limits spacifi ad in 10 CFR 50. 67, "Accident Source Term," (Ref. 4) .
If this occurred in conjunction with.a fuel cladding failure, fission products could enter the containment atmosphere.
APPLICABLE        The RCS safety/relief valves and the Reaotor Protection SAFETY ANALYSES  System Reactor Pressure-High Function have settings established to ensure that the RCS pressure SL will not be exceeded.
(continued)
* PBAPS UNIT 2                        B 2.0-7                        Revision No. 75
 
RCS P'ressure SL B 2.1.2
* BASES APPLICABLE        The RCS pressure SL has been selected such that it is at a SAFETY ANALYSES
* pressure below which it can be shown that the 1ntegr1ty of (continued)    the system is not endangered. The reactor pressure vessel is designed to Sectjon III, 1965 Edition of the ASME, Boiler and Pressure Vessel Code, including Addenda through the winter of 1965 (Ref. 5), which permits a maiimum pressure transient of 110%, 1375 psig, of design pressure 1250 psig.
The SL of 1340 ps1g is measured in the reactor steam dome.
The SL has been dete.rmined to be adequate to ensure tJ:le RCS pressure does not exceed the 1375 ps1g RCS pressure limit (Refs. 7 and 8). The RCS is designed to the ASME Section III, 1980 Edition, including Addenda through winter of 1981 (Ref, 6), for the reactor recirculation piping, which permits a maximum pre.ssure transient of 110% of design pressures of 1250 psig for suction piping and 1500 psig for discharge piping. The RCS pressure SL is selected to be the lowest transient overpressure allowed by the applicable codes.
SAFETY LIMITS    The maximum transient pressur.e allowable in the RCS pressure vessel under the ASME Code, Section III, is 110% of design pressure. The maximum transient pressure allowable in the RCS piping, valves, and fittings is 110% of design pressures of 1250 psig for suction piping and 1500 psig for dis,charge piping. The most l 1mit i ng of these a 11 owances is the 110%
of design pressures of 1250 psig; therefore, the SL on maximum allowable RCS pressure 1s e~tablished at 1340 psig, as measured at the reactor steam dome.
APPLICABILITY    SL 2.1.2 applies in all MODES.
SAFETY LIMIT VIOLATIONS (continued)
* PBAPS UNIT 2                        B 2.0-8                      Revision No. 148
 
RCS Pressure SL B 2.1.2
* BASES SAFETY LIM.IT VIOLATIONS (cont1nued) Exceeding the RCS pressure SL may cause 1mmed1ate RCS failure and create a potential for radioactive releases in excess of 10 CFR 50. 67, "Accident Source Term, " limits (Ref. 4). Therefore, it is required to insert all insertable control rods and restore compliance w1th the SL within 2 hours. The 2 hour Completion Time ensures that the operators take prompt remedial action and also assures that the probability of an acc1dent occurring during the period is minimal.
* REFERENCES    1. UFSAR, Section 1.5.2.2.
: 2. ASHE, Boiler and Pressure Vessel Code. Section III,
* Article NB-7000.
(continued)
* PBAPS UNIT 2                    B 2.0-9                    Revision No. 75
 
RCS Pressur-e SL B 2.1.2
* BASES REFERENCES    3. ASME, Boiler and Pressure Vessel Code, Sect1om XI, (continued)    Article IW-5000.
: 4. 10 CFR 50.67.
: 5. ASME, Boiler and Pressure Vessel Code, Section III, 1965 Edition, including Addenda to winter of 1965.
: 6. ASME, Boiler and Pressure Vessel Code, Section III, 1980 Edition, Addenda to wfnter of 1981,
: 7. G-080-VC-413, "Reactor Vessel Overpressure Protection."
GE Hitachi Nuclear fnergy, 26A832l, Revision 1.
: 8. G--080-VC-468, "Peach Bottom Units 2 & 3 Two Safety Relief Vatves Out-of-Service Evaluation," GE Hitachi Nuclear Energy, 004N6240-P, Revision 1.
* PBAPS UN.Ii 2                B 2.0-10                  Revision No. 148
 
LCD Applicabtlity B 3.0
* B 3.0 BASES LIMITING CONDITION FOR OPERATION (LCD) APPLICABILITY LCOs              LCD 3.0.1 through LCD 3.0.9 establish the general requirements applicable to all Specifications in Sections 3.1 through 3.10 and apply at all times, u:nless otherwise stated.
LCD  3.0.1        LCD 3.0.1 establishes the Applicability statement within eacti individual Specification as the requirement for when the LCD is required to be met (i.e., when the unit is in the MODES or other specified conditi-0ns of the Applicability statement of each Specification).
LCD  3.0.2        LCD 3.0.2 establishes that upon discovery of a failure to meet an LCD, the associated ACTIONS shall be met. The Completion Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered, unless otherwise specified.
The Requ1red Actions establish those remedial measures that
* must be taken within specified Completion Times when the requirements of an LCD are not met. This Specification establishes a.
                          -      that:
Completion of the Required Actions within the specified Com!}l eti on Ti mes constitutes compl i ,3nce with a Specification; and
: b. Completion of the Required Actions is not required when an LCD is rnet within the specified Completion Time, unless otherwise specified.
There are two basic types of Requtred Actions. The first type of Required Action specifies a time limit in which the LCD must be met. This time limit is the Completion Time to restore an inoperable system or component to OPERABLE status or to restore variables to within specified limits. If this type of Required Action ts not completed within the specified Completion Time, a shutdown may be required to place the unit in a MODE or condition in which the Specification is not applicable. (Whether stated as a Required Action or not, correction of the entered Condition is an action that may always be considered. upon entering ACTIONS.) The second type of Required Action specifies the
* PBAPS UNIT 2                          B 3.0-1                      Revision No. 156
 
LCO Applicability B 3.0 BASES LCC 3.0.2    remedfal measures that permit continued operation of the (continued) unit that is not further restricted by the Compl etiorl Time ..
In this case, compliance with the Required .Actions provides an acceptab~e level of safety for continued operation.
Completing the Required Actfons is not required when an LCO is met or is no longer applicable, unless otherwise stated in the 1ndividual Speciftcations.
The nature of some Req;. dred Actions of some Conditions necessitates that, once the Condition is eAtered, the Required ActioRs must be completed even though the associated Condition ncr longer exists. The individual LCO's ACTIONS specify tlie Reqaired Actions where this is the case.
An example of t~is is fn LCO 3.4.~. <<RCS Pressure and Tempera~ure Limits."
Tlie Completion Times ,of the Required Actions are also applicable when a system or component is removed from service intertionally. The ACTIONS for not meeting a si'ngle LCO adequately manage any increase in plant risk, provi ded 1
any unusual external conditions (e.g., severe weather, offsite power instability) are considered. In addition, tlie i ncr-e.a_s,ed risk associated wit fl. simultaneous,. removal -of*
multiple structures, systems, trains, or components from se,rvice is assessed and managed in accordance with 10 CFR
* 50.65(a)(4). fndividual Specificat1ons may specify a. ti'me l 'irni t 70r performing an SR when equipment is removed fr*om ser'.!i ce or b-ypassed for testing. In ttii s ca,se I the Completion Ti:i!es of the ReC't;ired Actions are applicable when tnis tir.ie limit ex;:)ires_, if the eqJipment rerr:'ains removed from service or by?assed.
When a ch~nge in. MODE or other speci fi e,d cdndi ti on is required to comply with Required Actions, th,e unit may enter a MODE or other specified conditio1 in whicb another Soecification becomes applicable. In this case, the Comoletio~ Times of the associated Required Actio1s would apply from the poirr: ~n ttme that the new Sp.ecification becomes applicable and th~ ACTIO~S ConditionCs) are entered:
(continued)
* PBAPS UNIT 2                        B 3.0-2
 
LCO Applicability B 3.0 BASES  (continued)
LCO  3.0.3        LCO 3.0.3 establishes the actions that must be implemented when an LCO is not met and:
: a. An associated Required Action ar:d Completion Time is not met and no other Condition applies; or
: b. The condition of the unit is not spe~ifically addressed by the associated ACTIONS. Th is means that no combination of Conditions stated in the ACTIONS can be made that exactly correspo~ds to the actual condition of the unit. Sometimes, possible c.ombinations of Conditions are such that entering LCO 3.0.3 ts warranted; in such cases, the ACTIONS specifically state a Condition corresponding to such combinations and also that LCO 3.0.3 be entered immediately.
This Specification delineates the time limits for placing the unit in a safe MODE or othe.r specif1ed condition when operation carnot be mainta  ned within the limits for safe operation as aef1ned by t~e LCO and its ACTIONS. Planned
* entry into LCO 3.0.3 should be avoided. If it is not practicable to avoid planned entry into LCO 3.0.3, pla~t risk should be assesses and ma~aged jn accord~nce wjth 10 CFR 50.65 (a)~4). and the planned entry into LCO 3.0.3 should have less effec~ on ~lant safety than other practicable alternatives.
Upon entering LCO 3.0.3, 1 ~our is allowed tb prepare for an orderly shutdown before initiating a change in ur.it operation. This includes time to permit the operator to coordinate the reduction in electrical generation wit'1 the loa~ dispatcher to ensure the stabilfty and availabili:y of the electrical grid. The time limits specifled to enter lower MODES of operation permit tne shutdown to proceed in a controlled ard orderly manner that is well within t~e s~ecified maximum cooldown rate and within the capabilitjes of the unit, assuming that only the minimum required equipment is O,PERABLE. This reduces thermal stresses 0'1 components of the ~eactor Ccol ant System ar.d the pctenti al for a plant upset that could challenge safety syste~s under conditions t,o which this Specification applies. The use and interpretation of specified times to complete the actions of LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times .
* PBAPS UNIT 2                          B 3.0-3                    Revision No. 152
 
LCO Applicability B 3.0
* BASES LCO 3.0.3    A  unit shutdown required in accordance with LCO 3.0.3 may be (continued) terminated. and LCO 3.0.3 exited if any of the following occurs:
: a. The LCO is now met.
: b. The LCO is no longer applicable.
: c. A Condition exists for whi,h the Required Actions have now been performed.
: d. ACTIONS exist that do not have expired Completion Times. These Completion Times are applicable from the point in time that the Condition is initially entered and not from the time LCO 3.0.3 is exited.
The time limits of Specification 3.0.3 allow 37 hours for the unit to be in MOOE 4 when a shutdown is required during MODE 1 operation. If the unit is in a lower MODE of operation when a shutdown is required, the time limit for entering the next lower MODE applies. If a lower MODE is entered in less time than allowed, however, the total
* a1lowable time to enter MODE 4, or other applicable MODE, is not reduced. For example, if MODE 2 is entered in 2 hours, then the time allowed. for entering MODE 3 is the next 11 hours, because the total time for entering MODE 3 is not reduced from the allowable li'mit of 13 hours. Therefore, if remedial measures are completed that would permit a return to MODE 1, a penalty is not incurred by havii:ig to enter a lower MOOE of operation in less than the total time allowed.
In MODES 1, 2, and 3, LCO 3.0.3 provides actions for Conditions not covered in other Specifications. The requirements, of LCO 3. O. 3 do not app1 y in MODES 4 and S because the unit is already in the most restrictive Condition required by LCO 3.0.3. The requirements of LCO 3.0.3 do not apply in other specified conditions of the Applicability (unless in MODE 1, 2, or 3) because the ACTIONS of individual Spec;ifications sufficietttly define the remedial measures to be taken.
Excepti ans to LCO 3. 0. 3 are p,rovi ded in instances where requiring a unit shutdown, in accordance with LCO 3.0.3, would not provide appropriate remedial measures for the associated condition of the unit. An example of this is in LCO 3.7.7, "Spent Fuel Storage Pool Water Level." LCO 3.7.7 has an Applicability of "During movement of fuel assemblies (continued)
PBAPS UNIT 2                      B 3.Q-4                        Revision No. 141
 
Leo Applicability B 3.0
* BASES LCO 3.0.3 (continued) in the spent fuel storage pool." Therefore, this LCO tan be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3.7.7 are not met while in MOOE 1, 2, or 3, there is no safety benefit to be gained by plating the unit in a shutdown condition. The Required Action of LCO 3 .. 7, 7 of "Suspend movement of fuel assemblies in the spent fuel storage pool" is the appropriate Requir'ed Action to complete in 1ieu of the actions of LCO 3.0.3. These exceptions are addressed in the individual Specifications.
LCQ  3.0.4  LCO 3,0.4 establishes limitations on changes ir:t MODES or other specified conditions in the Applicability when an LCO is not met. It allows placing the unit in a .MODE or other specified condition stated in that Applicability (e.g., t~e Applicability desired to be entered) when unit conditions are such that the requirements of the LCO would not be met, in accordance with either LCO 3.0.4.a, LCO 3.0.4.b, or LCO 'I 3.0.4.c.
LCO 3.0.4.a allows entry into a MODE or other specifie<l condition in the Applicability with the LCO not met when the associated AffiONS to be entered following entry into the MODE or other specified condi.tion in the Applicability will permit continued operation within the MODE or other specified condition for an unlimited period of time.
Compliance with ACTIONS that permit continued operation of the unit for an unli.mited period of time in a MODE or other
* specified condition provides an acceptable levei of safety for continued operation. This is without rcegard to the status of the unit before or after the MODE change.
Therefore, in such cases, entry into a MODE or other specified condition in the Applicability may be made and the Required Actions followed after entry into the Applicability.
For example., LCO 3.0.4.a may be used when the Required Action to be entered states that an inoperable instrument channel must be placed in the trip condition within the Completion Time. Transition into a MOOE or other specified condition in the Applicability may be made in accordance with LCO 3.0.4 and the channel is subsequently placed in the tripped condition within the Completfon Time, which begins when the Applicability is entered. If the instrument channel cannot be placed in the tripped condition and the subsequent default ACTION ("Required Action and associated Completion Time not met") allows the OPERABLE traih to be placed in operation, use of LC:O 3.0.4.a is acceptable because the subseqtient ACTIONS to be entel"'ed followin~ entry into the MODE include ACTIONS (place the OPERABLE train in.
operation) that permit safe plant operation for an unlimited period of time in the MODE or other specified condition to be entered.
* LCO 3.0.4.b allows entry into a MODE or other specified condition in the Applicabi1ity with the LCO not met 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.
(continued)
PBAPS UNIT 2                      B 3.0-5                    Revfaion No. 141
 
LCO App1icability B 3.0
* BASES
  -------------~--~----~------------'---
LCO 3.0.4    The risk assessment may use quantitative, qualitative, or *
(continued) blended approaches. and the risk assessment will be conducted using the plalilt program, pr.ocedures, and criteria in place to implement 10 CFR 50,65(a)(4), which requires that ri.sk impacts of maintenance activities be assessed and managed. The risk assessment, for the purposes of LCO 3.0.4.b, must take into account a11 inoperable Technica1 Specification equi.pment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)(4) risk assessment scope. The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, "Assessing and Managing Risk Before, Maintenance Activit-ies at Nuclear Power Plants."
Regulatory Guide 1.182 endorses the guidance. in Section 11 of NUMARC 93-01, '"Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."
These documents address general g.uidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management acti.orts, and example risk management actioAs. These include actions to plan and conduc:t other activities in a. manner that controls overall risk, increased risk awareness by shift and management personnel, actions*to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment .of backup success paths or compensatory Teasures), and determi.nati 9n that tite proposed. MODE change
                ,s acceptable. Consideration should also be given to the probability of completing restoration such that the requirements of the LCO would be met pr:i or to the expiration of AffiONS Completion Times that would requ.ire exiting the Applicability.
LCO 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-01 p.rovides guidance relative to consideratiori or simultaneous unavailability of multiple systems and components.
The results of the risk assessment sha,1,1 be considered in determining the acceptability of entering the MODE or otlier specified Cohdition in th~ Applicability. and any            .
co.rresponding risk management actions. The LCO 3.0.4.b risk assessments do not have to be documented.
The lechnical Specifications a.llow continued operation with equipment unavailable in MoDE 1 for the duration of the Completion Time. Since. this is allowable, and siAce in general the risk impac:t in that particular MODE bouods the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the LCO, the use of the LCO 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed and managed as. stated above. However there is a. small subset f
{continued)
* PBAPS UNIT 2                    B 3.0-Sa                    Revision No. 141
 
LCO Applicability B 3.0
* BASES LCO 3.0.4      of systems and components that have been determined to be (conti.nued) more important to risk and use of the LCO 3.0.4.b allowance is prohibited. The LCOs governing these system and components contain Notes prohibiting the use of LCO 3.0.4.b by stating that LCO 3.0.4.b is .not applicable.
LCO 3,0,4.c a.11ows entry into a MODE or other specified condition in the Applicability with the LCO not met based on a Note in the Specification which states LCO 3.0.4.c is applicable. T11ese specific allowances permit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be. eAtered do not J;>rovi de for continued operation for an unlimited period of time and a risk assessment has not been performed. This allowance may apply to all the ACTIONS or to a specific Required Action of a Specification. The risk assessments performed to justify the use of LCO 3.0.4.b usually only consider systems and components. For this reas.on, LCO 3.0.4.c is typically applied to Specifications which describe values and (continued)
* PBAPS UNIT 2                    B 3.0-Sb                    Revision No. 141  I
 
LCO Applicability B 3.0 BASES LCO 3.0.4      parameters (e.g., Reactor Coolant System specific activity),
(co.ntinued} and may be applied to other Specifications based on NRC plant-specific approval.
The provisions of this Specification shdul-d not be interpreted as endorsing th.e failure to exercise the good practice of restoring systems or components to OPERABlE s.tatus before entering an associated MODE or other specified condition in the .Applicability.
The provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are requir*ed to comply with .ACTIONS. In addition, the provisions of_L~O 3.0.4_s~all ~ot prev~nt_cha~g~s in MODES or other spec1f1ed cond1t1ons 1n the Appl1cab1l1ty that result from any unit shutdown. In this context, a unit shutdown 1s defined as a ~hange in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, and MODE 3 to MODE 4.
Upon entry into a MODE or other specified condition in the Applicability with the LCO not met, LCO 3.0.1 and LCO 3.0.2 require entry 9nto the applicable Conditions and Required Actions until the Condition is resolved, until the LCO is met, or until the unit is not within the Applicability of the Technical Specification.
Survei 11 ances do not have to be p-erformed on the associated inoperable equipment (or on variables outside the specified limits),_as permitted by SR 3.0.1. Therefore, utilizing LCO 3.0.4 is not a violation of SR 3.0.1 or SR 3.0.4 for ar:iy Surveillances that have not been performed on inoperable equipment. However, SRs must be met to ensure OPERABILITY prior to declaring the associated equipment OPERABLE (or variable within limits) and restoring compliance with the affected LCO.
LCO  3.0.5    LCO 3.0.5 establishes thee allowance for restoring equipment to service under administrative controls when it has been removed from service or declared inoperable to comply with ACTIONS. The sole purpose of tnis Specification is to provide an exception to LCO 3.0.2 (e.g., to not comply with the applicable Required Action(s)) to allow the performance of SRs to demonstrate:
: a. The OPERABILITY of the equipment being returned to service; or
: b. The OPERABILITY of other equipment.
* PBAPS UN IT 2                      B 3. 0-6 contin ed Revision No. 52
 
LCO Applicability B 3.0
* BASES LCO 3.0.5    The administrative controls ensure the time the equipment is (continued) returned to service ill conflict with th*e requirements of the ACTIONS is limited to the time absolutely necessary to perform the al lowed SRs. This Specification does not provide time to perform any other preventi:ve or corrective maintenance. LCO 3.0.5 should not be used in lieu of other practicable alternatives that comply with Required Actions and that do not require changing the MODE or other specified condit'ions in the Applicability in order to demonstrate equipment is OPERABLE. LCO :3.0.S is not intended to be used repeatedly.
An example of demonstrating equipment is OPERABLE with the Required A~tions not met would be returning a Control Rod Drive (CRD) Hydraulic Control Unit (HCU) td service in order to perform testing .to demonstrate that the CRD is now OPERABLE following HCU maintenance.
Examples of demonstrating equipment OPERABILITY include instances in which it is necessary to take an inoperable channel or trip system out of a tripped condition that was directed by a Required Action, if there is no Required Action Note for this purpose. An example of verifying OPERABILITY of equipment removed from service is taking a tripped chanr:,el out of the tri-pped condition* to* permit the logic to function and indicate the appropriate response during performance of required testing on the inoperable channel.
Examples of demonstrating the OPERABILITY of other equipment are taking an inoperable channel or trip system out of the tripped condition 1) to prevent the trip function from occurring during the performance of a:n SR on another channel in the other trip system, or 2) to permit the 1ogic to function and indicate the appropriate response during the perfo.rmance of an SR on another channel in the same trip system.
The admir:iistrative controls in LCO 3.0.5 apply in all cases to systems or components in Chapter 3 of the Technical Specifications, as long as the testing could not be conducted while complying'with the Required Actions. This includes the realignment or repositioning of redundant or alternate equipment or trains previously manipulated to comply with ACTIONSr as well as equipment removed from service or declared inoperable to comply with ACT!ONS.
Ccontin!;led)
PBAPS UNIT 2                      8 3.0-7                    Revision No. 141
 
LCO Applicability 8 3.0
* BASES LCO  3.0.6  LCO 3.0.6 establishes an exception to LCO 3.0.2 for support systems that ha;t1e an LCO specified in the Tec:Elnital Specifications (TS). This exception is provided because LCO 3.0.2 would require that the Conditions and Required Actions of the associated i'noperable supported system LCO be entered solely due to the inoperability of the support system. This excep.tion. is justified because the actions that ar~ required to ensure the plaRt is maintained in a safe condition are specified in the support systems' LCO' s Required Acti ans. These Required Acti ans may include ehtering the supported system's Conditions and Required Actions or .may specify other Required Actions.
              'When a support system is inoperable and there is an LCO specified for it in the TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability.
However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported Ccontinued)
* PBAPS UNIT 2                    B 3.0-7a                  Revision No. 141  I
 
LCO Applicability B 3.0
* BASES LC O 3.0.6    systems' LCOs' Conditions and Required Actions are (continued) eliminated by providing all the actiOns that are necessary to ensure the plant is maintained in a safe condition in the support syst,em''S Required Actions.
However, there are instances where a, support system's Required Action may either direct a supported system to be declared i,noperable or dfrect entry into Conditions and Re<,uired Actions for the supported system. This may occur iumediately or after some specified delay to perform some other Required Action. Regardless of whether it is innediate or after some delay, when a support system's Required Action directs a supported system to be dec,lared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable, Conditions and Required Act i ans sha11 be: entered in accordance with lCO 3.0.2.
Specification 5.5.11, asafety Function Detenninatton Program (SFDP), ensures loss of safety function is detected and 8
appropriate actions are taken. Upon entry into LCO 3.0.6, an evaluation shall be made to detennine if loss of safety function exists. Additionally, other li'ntitations, remedial actions, or compensatory actions may be identified as a result of the support system inoperabil1ty and corresponding extept7ton "to entering supported -system,- Condi ti ons---a,nd  ., --
Required Actions. The SFDP implements the 'requirements of LCO 3.0.6.
Cross division &#xa2;hecks to identify a loss of safety function for those support systems that support safety systems are required. The cross division check verifies that the supported systems of the redundant OPERABLE support system are OPERABLE, thereby ensuring safety function is retained.
If' this evaluation d'e,termines that a loss of safety function exists, the appropriate Conditions and Required Actions of the LCO in which, the loss of safety function exists are required to be entered.*
LCO 3.0.7      There are certain special tests and operations required to be. performed at various times over the life of the unit.
These special tests and operations are necessary to demonstrate select unit performance characteristics, to perform special maintenance acti*vities, and to perfonn
{continued)
PBAPS UNIT 2                      B 3.0-8                          Revision No. O
 
LCD Applicability B 3.0
* BASES LGO 3.0.7 (continued) special evo1utions. Special Oper,ation.s LCOs in Section 3.10 allow specified TS r~quirementt to be changed to permit performances of these special tests and operations, which otherwise could not be perfo~med if required to comply with the requirements of these TS. Unless otherwise specified, all the other TS requirements remain unchanged. This will ensure all appropriate requirements of the MODE or other specified co~dition not directly associated with or required to be* changed tb perform the spe.cial test or operation will remain in effect.
* The Applicability of a Special Operations LCO represents a tondition not necessarily i~ compliance with the normal requirements of the TS. tompliance with Special Operations LCOs is opttonal. A special ope~ation may be performed either under the provisions of the appropriate Special Operations LCO or under the other applicable TS requirements. If it is desired to perform the special operation under the provisions of the Special Operations LCD, the requirements of the Special Operations LCO shall tre followed. When a Special Operations LCO requires another LCO to be met, only th.e requirements of the LCD statement are required to be met regardless of that LCO's Applicability (i.e., should the requirements ef this other LCD not be met, the ACTIONS of the Special Operations LCD apply, not the ACTIONS of the other LCO). However, there are instances where the Spe.cial Qperatio,ns LCO's ACTIONS may direct the other LCO's ACTIONS b~ met. The -
Surveillances of the other LCO are ~ot required to be met, unless specified in the Special Operati0ns LCD. If conditions exist such that the Applicability of any 6ther LCO is met, all the other LCO's requirements (ACTIONS and SRs) are required to be met concurrent with the requirements of the Special Operations LCO.
LCO 3.0.8      LCO 3.0,8 establfshe~ conditions under wh1ch systems are considered to remain capable of performing their intended safety function when associatd snubbers are not capable of providirtg their associated support funct1on(s). Thts LCD states that the s~pported system is not coDsidered to be tnoperabla solely due to one or more snubbers not capable of performing their associated suppor,t function(s). LCO 3.0.8 may also 6e applied to exclude penetration flow paths with nonfunctiona,l snubbers from LC0 3.5.4 RPV WIC Drain Time Calculation.
This is appropriate because a 1tm~ted length of time is allowed. for maintenance, testing, or repair of one or more snubbers not capa.ble of performing their associated support function(s) and appropriate compensatory measures are specifted in the snubber requirements, which a0e lotated
* PBAPS UNIT 2                    B 3.0-~                    Revision No. 145
 
LCD Applicability B 3.0
* BASES LCD 3.0.8 (continued) outside of the Technical Specifications (TS) under lice,nsee control. The snubber requirements do not meet the criteria in 10 CFR 50.36(c)(2)(ii}, and, as such, are appropriate for control by the licensee.
* If the all~wed time expires and the snubber(s) are unable to perform their associated support function(s), the affected supported system's and DRAIN TIME LGO(s) must be declared not met and the Conditions and Required_ Actions entered in accordance with LCD 3.0.2.
The optional allowance of TS 3.0.8 to 'not declare the supported (sub)system(s) LCO(s) not met for inoperable snubbers may be used at PBAPS for snubbers that have a seismic-only function in addition to other required loading function&-such as a hydro-dynamic function during the applicable operating condition. Prior to using LCD 3.0.8, it must be confirmed that the requirements of TRM 3.16 SNUBBERS a re met.
LCO 3.0.8.a applies when one or more snubbers are not capable of providing their associated support function(s) to a single train or subsystem of a multiple train or subsystem supported system or to a single train or subsystem supported system.
* LCO 3.0.8.a allows 72 hours to restor~ the snubber(s) before declaring the supported system inoperable or calculating the associated DRAIN TIME. The 72 hour Completion Time is reasonable based on the low probability of a seismic event concurrent with ah event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function and due to the availability of the redundant train of the supported system.
LCD 3.0.8.b applies when one or more snubbers are not capable of providing their associated support function(s) to more than one train o.r subsystem of a multiple train or subsystem supported system. LCO 3.0.8.b allows 12 ~Gurs to restore the snubber(s) before declaring the supported system inoperable or calculating the associated DRAIN TIME. The 12 hour Completion Time is reasonable based on the Tow probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) is Care) not capable of performing their associated support function(s) .
* PBAPS UN IT 2                  B 3,D-9a                    Revision No . 145
 
LCO Applicabflity B 3.0
* BASES LCO 3.0.8
( centi nued)
Reference TRM 3.16 SNUBBERS Bases for requirements and c:omrnitments for mai ntai ni ng mi 11*imum .supporting eqlli pment not ass*oci ated With the inoperable snubber Cs) when entering LCD 3.0.8.a or LCD 3.0.8.b.
When apply-ing LCO 3 . 0.8.a or LCO 3.0.8.b one of the following two means of heat removal mus.t be available 1) at le~st one high pressure makeup path (i.e., using high pr*e.ssure <.:oolant inJection CHPCI) or reactor core isolation cooling (RCIC)) and hec!t removal capability (i.e.,
suppression pool cooling), including a minimum set of stlpporting equipment required for success, not associated wi'th the inoperable snubber.(s), or 2) at least one low pressure makeup path (i.e., low pressure coolant injection (LPCI) or* core spray (CS)) and h*_eat removal capabi'lity (i.e .* suppression pool <oooling or shutdown cooling),
ir1cluding a minimum set of supporting equipmenti not associated with the inoperable snubber(s).
LCO 3.0.8 requires that risk be assessed and managed.
I~dustry'and NRC guidance on the implementation of 10 CFR 50.65(a)(4) (the Maintenance Rule) does not address sefsm1c risk. However, use of LCO 3.0.8 should be cons1de~ed with respect to other p7ant maintenance activities, and integrated into th.e existing Maintenance Rule proces.s to the extent possible so that maintenanc:e on any unaffected train or .subsystem is properly controlled, and emergent issues are properly addressed. The risk assessment need not be quantified, bt1t may be a qualitative aware-riess of the vulnerability of systems and components When one or more snubbers are not able to perform the.i r associated support function. Reference TRM 3. Hi. Bases for risk management actions used to satisfy commitments T04781 and T04782.
LCD 3.0.8 does not apply to non-seismic functions of snubbers. Prior to using LCD 3.0.8 .. a for seismic snubbers that may also have non-seismic functi,orrs, it must be conf1 rmed that at least one train of eac.h system that is supported by the inoperabl*e snubber(s) would remain capable of performing the system's required safet1 or support functions for postulated design loads other than ssismic loads. LCO 3.0.8.b is not to be applied to seismic snubbers that also have non-seismic functions .
* PBAPS UN IT 2                        B 3.0-9b                        Revision No. 156
 
LCO Applicability B 3.0
* BASES LCO 3.0.9    LCO 3.0.9 establishes conditions under which sy5,tems described in the Technical Specifications are considered to remain OPERABLE when required barriers are not capable of providing their related support funttion(s).
Barriers are doors, walls, floor plugs, curbs, hatches, installed structures or components, or other devices, not explicitly described in Technical Specifications, that support the performance of the safety function of systems described in the Technical Specifications. This LCO states that the supported system is not constdered to be inoperable solely due to re*qui red barriers not capable of performing their related suppo.rt functian(s) under the described conditions. LCO 3.0.9 allows 30 days before declaring the supported sys.tem(s) inoperable and tl:1e LCO(s) associated with the supported :s.ystem(s) not met. A maximum time is placed on each use of this allowance to ensure that as required barriers are found or are otherwise made u.nava1lable, t-hey are restored. However, the allowable.
du.ration may be less than the specifted maxirnum time based on the risk assessment.
If the allowed time expires and the barriers -are unable to perform their related support function(s), the s*upported system's LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3. O. 2.
This provision does not apply to barriers which support ventilation systems or to fire barriers. The Technical Specifications for ventil~tion systems provide specific Conditions for inoperable barriers. Fire barriers are addressed by other regulatory requirements and associated plant programs. This provision does not apply to barriers which are not required to support system OPERABILITY ( see NRC Regulatory Issue Summary 2001-09, "Control of Hazard Barriers," dated April 2, 2001).
The provtsions of LCO 3.0.9 are justified because of the low risk associated with required barriers not being capable of performing their related support function. This provision is based on consideration of the followi.ng initiating event categories:
* loss of cool ant accidents;
* High energy l i rle breaks;
* f'eedwater line breaks;
* Internal flooding;
* External, flooding;
* Turbine missile. ejectfon; and
* Tornado or high wind .
* PBAPS UN IT 2                    B 3. 0-9.c                Revision No .. 156
 
LCO App1icab1lity B 3.0
* BASES LCO 3.o.g (continued)
The risk impact of the barriers Which cannot perform their related support function(s) must be addressed pursuant to the risk assessment and management provision of the Maintenance Rule, 10 CFR 50.65(a)(4), and the associated i mpl ementati on guidance, Regulatory Gui de 1.160, "MOnitori ng the Effectiveness of Maintenance at Nuclear Power Plants."
Regulatory Gui de 1.160 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." This guidance provides for the consideration of dynamic plant configuration issues, emergent conditions, and other aspects pertinent to plant operation with the barriers unable to perform their related support function(s). These considerations may resu1t in risk management and other compet:1satory actions being required during the period that barriers are unable to perform their related support function (s).
LCO 3.0.9 may be applied to one or more trains or subsystems of a system supported by barriers that cannot provide their related support function Cs), provided that risk i-s assessed
* and managed (including consideration of the effects on Large Early Rel ease and from external events). If applied concurrently to more than on,e train or subsystem of a multiple train or subsystem supported system, the barriers supporting each of these trains or subsystems must provide their related support fijnction(s) for different categories of initiating events. For example, LCO 3.0.9 may be applied for ~p to 30 days for more than one train of a multiple train supported system if the affected barrier for one train protects against internal flooding and the affected barrier for the other train protects against tornado missiles. In this example, the affected barrier may be the same physical barrier but serve differeAt protection functions for each train.
The HPCI (High Pressure Coolant Injectio,t1) and RCIG (Reactor Core Iso1ation Cooling) systems are singl,e train systems for injecting makeup water into the reactor during an accident or transient event. The HPCI system provides backup in case of a RCIC system failure. The ADS (Automatic Depressurization System) and low pressure &#xa3;CCS coolant injection provide the core cooling function in the event of failure of the HPCI system during an accident .
* .PBAPS UNIT 2                      B 3.0-9d                    Revision No. 156
 
L(O Applicability B 3.0
* BASES LCO 3.0.9 (continued)
Thus, for the purposes of LCO 2.0.9, the HPCI system, the RCIC system, and the ADS are considered independent subsystems of a single system and LCO 3. 0. 9 can be. used on these single train systems in a manner similar to multiple train or subsystem systems.
If during the time that LCO 3.0.9 1s being used, the required OPERABLE train or subsystem becomes inoperable, it must be restored to OPERABLE status within 24 hours.
Otherwise, the train(s) or subsystem(s) supported by barriers that cannot perform their related support function(s) must be declared inoperable and the assaciated LCOs declared not met. This 24 hour period provides time to respond to emergent conditions that would ot~erwise likely lead to ent~y into LCO 3.0.3 and a rapid plant shutdown, Which is not justified given the low probability of an initiating event which would require the barrier(s) not capable of performing tFleir re1ated support function(s).
During this 24 hour period, the plant risk associated with the existing conditions is assessed and managed in accordance with 10 CFR 50.65(a)(4) .
* PBAPS UN IT 2                  B 3.0-9e                      Revision No.156
 
SR Appl i cabi1 ity B 3.0
* B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY BASES SRs              $R 3.0.1 through SR 3.0.4 establish  the general requirements applicable to all Specifications in  Sections 3.1 through 3.10 and apply at all times, unless  otherwise stated. SR 3.0.2 and SR 3.0.3 apply in Chapter  5 only when invoked by a Chapter 5 SpecifiGation.
SR  3.0.l        SR 3.0.1 establishes the requireme11t that SRs must be met during tbe MODES or other specified conditions in the Applicability for which the requirements of the LCO apply, unless otherwise specified in the individual SRs. This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with SR 3.0.2, constitutes a failure to meet an LCO.
Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this
* Specification, however, is to be construed as implying that systems or components are OPERABLE when:
: a. The systems or components are known to be inoperable, although still meeting the SRs; or
: b. The requirements of the Surveillance(s) are known to be not met between required Surveillance performances.
Surveillances do not have to be performed when the unit is in a MODE or other specified condition for which the requirements of the associated LCO are not applicable, unless otherwise specified. The SRs associated with a Special Operations LCO are only applicable when the Special Operations LCO is used as an allowable exception to the req&#xb5;irements of a Specification.
Surveillances, intluding Surveillances invoked by Required
                  .Actions, do not have to be performed on inoperable equipment
                  *because the AmONS define the remedial measures that apply.
Surveillances have to be met and performed in accordance with SR 3.0.2, prior to returning equipment to OPERABLE status.
Ccontint1ed)
* PBAPS UNIT 2                        B 3.0-10                    Revision No~ 140
 
SR Applicability B, 3.0
* BASES SR 3.0. I (continued)
Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with SR 3.0.2. Post maintenance testing may not be possible in the current MODE or other specified conditions in the Applicability due to the necessary unit parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the, extent possible and the equipment is not otherwise believed to be incapable of perfonning its function. This will allow operation to 0
proceed to a MODE or other specified condition where other necessary post maintenance tests can be completed.
Some examples of this process are.:
: a. Control Rod Drive maintenance during refueling that-requires scram testing at> 800 psi. However, if other appropriate testing is satisfactorily completed and the scram time testing of SR 3.1.4.3 is satisfied, the control rod can be considered OPERABLE. This allows startup to proceed to reach 800 psi to perform other necessary testing.
: b. High -pressure-coolant-injection (HPfrli maintenance during shutdown that requires. system functional tests at a specified pressure. Provided other appropriate testing is satisfactorily completed, startup can proceed with HPCI considered OPERABLE. This allows operation to reach the specified pressure to complete the necessary post maintenance testing.
SR 3 *. 0.2    SR 3.0.2 establishes the requirements for meeting the specified Frequency for Survefl 1ances and any Required Action with a Completion Time that requires the periodic perfonnance of the Required Action on a nonce per ***
* interval.
SR 3.0.2 permits a 25% extension of the interval specified in the Frequency. This extension facil i tates Survei 11 ance scheduling and considers plant operating conditions that may not be suitable for conduct tng the Surve 11 lance {e.g. ,
transient conditions or other ongoing Surveillance or maintenance activities).
(continued)
* PBAPS . UN IT 2                                                  Revision No. 0
 
SR Applicability B 3.0
* BASES SR 3.0.2      The 25% extension does not significantly degrade the (c;ontinued) reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particu1ar Surveillance being performed is the verification of conformance with the SRs. The exceptions to SR 3.0.2 are those Surveillances for which the 25% extension of the interval specified in the Frequency does not apply. These excep,tions are stated im the individual Specifications. The requirements of regulations take precedence over th TS. Therefore, when a test interval is specified in the regulations, the test interval cannot be extended by the TS, and the SR include a Note ill the Frequency stating, "SR 3.0.2 is not applicable."
An example of an exception when the test interval iS not
* specified in the regulations is the Note in the Primary Cl.>ntai nment Leakage Rate Testing Program, SR 3. O. 2 is riot 11 applicable." This exception is provided because the program already includes extensior:i of test intervals.
As stated in SR 3.0.2j the 25% extension also does not apply to the initial portion of a periodic Completion Time that requires performance on a "once per .... " basis. The 25%
* extension applies to each performance after the initial performance. The initial performance of the Required Action, whether it is a. particular Surveillance or some other remedial action, is conside,red a single action with a single Completion Time. One reason for not allowing the 25%
extension to this Completion Time is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes the function of the inoperable equipment in an alternative manner.
The provisions of SR 3.0.2 are not intended to be used repeatedly to extend Surveillance intervals (other than those consistent with ref~eling intervals) or periodic Completion Time intervals beyond those specified.
SR  3.0.3      SR 3.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been performed witl:lin the specified FreqL1ency. A delay period of up to 24 hours or up to the limit of the specified (continued)
* PBAPS UNIT 2                      B 3.0-12                    Revision No. 141
 
SR Appl i cabi l i tY B 3.0
* BASES
  --------------------------------~-----'----
SR 3.0.3      Frequency, whichever is greater, applies from the point in (continued) time that it is discovered that the Surveillance i:Jas not been perfo~med in accordance with SR 3.0~2. and not at the time that the s&#xb5;ecifi.ed Frequency was not met.
This delay period provides adequate time to perform Surveillances that have been missed. This delay period permits the performance of a Surveillance before complying with Required Actions or other remedial measures that might preclude. performance of the Survei 11 ance.
The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to pe.rform the Surveillance, the safety significance of the delay ir:i completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements.
When a Surveillance with a Frequency based not on time intervals, but upo~ spectfied unit conditions, operating situations, or requirements of regulations (e.g.~ prior to entering MODE 1 after each fuel loading, or in accordance.
with 10 CFR SO, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, SR 3.0.3 allows for the full delay period of up to t~e specified Frequency to perform the Surveillance.
However, since there is not a time i.nterval specified, the missed Surveill a.nee should be performed ,at the first reasonable opportunity.
SR 3.0.3 provides a time 1ir:nit for, and allowances for the performance of, Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.
SR 3.0.3 is only applicable if there is a reasonable expectation the associated equipment is OPERABLE or that variables are within limits, and it is expected that the Surveillance will be met when performed. Many facto.rs should be considered, such as the period of time since the Surveillance was last performed, or whether the. Surveillance, or a portion thereof, has ever been pe.rformed, and any other indkations, tests,. or activities that might support the expectation that the Surveillance will be met when performed.
An example of the use of SR 3.0.3 would be a relay contact that was not tested as required in accordan~e with a particular SR, but p.revio1,1s successful performances of the SR included the re1ay contact; the adjaceat, physically connected relay contacts were tested during the SR performance;. the subject re 1ay contact has been tested by another SR; or historical operation of the subject relay contact has been successful. It is not sufficient to infer the behavior of the associated equipment from the performance
{continued)
PBAPS UNIT 2                      B 3.0-13                    Revision No. 141
 
SR Applicability B 3.0
*. BASES SR  3.0.3    of simi1ar equipment. The rigor of determi  1ng whether there (continued) is a .reasonable expectatior:i a Surveillance will be met when performed should increase based on the length of time sirTce the last pe.rformance of the Surveillance. If the Surveillance has been perfo,.med r-ecent1y, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable expectation that the Surveillance will be met when performed. For surveillances that have not been performed for a 1ong pe.ri od or that have.
never been performed, a rigorous evaluation based on objective e~idence should provide a high degree of confidence that the equipment is OPERABLE. The evaluation should be documented in sufficient detail to allow a knowledgeable individual to understand the basis for the determination.
Failure to comply with specified Frequencies for SRs is expected to be an infrequent occ1.ffrence. Use of the. delay period established by SR 3.0.3 is a flexibility which is not intended to be used repeatedly to extend Surveillance intervals. While up to 24 hours or the limit of the specified Frequency is provided to perform the. mi.ssed Surveillance1 it is expected that the missed Surveinance will be performed at the first reasonable opportunity. The
* determination of the first reasonable opportunity should include consideration of *the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plaf!lt down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availability of personnel, and the time required to perform the Surveillance.
This risk impact should be managed through (continued)
PBAPS UNIT 2                    8 3.0-13a                    Revision No. 141
 
SR Applicability B 3.0 BASES SR  3.0.3      the program in place to implement 10 CFR 50.65(a)(4) and its (continued)  implementation guidance. NRC Regulatory Guide 1.182,
                  'Assessing and Manijging Risk Before Maintenance Activities at Nuclear Power Plants.' This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action t~resholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory 'Gui de. The risk evaluation may use qu.antitat1ve, qualitative, or b1ended methods~ The degree of depth and rigor of the evaluation should be commensurate with the importance of the component.
Missed Survefl lances for important* components .should be analyzed quantitatively. If the results of the risk evaluation d~termine the risk increase is significantj this evaluation should be used to determfne the safest course of
                -action. All missed Surveillances will be placed in the licensee's Corrective Action, Program.
If a Surveillance is not completed within the allowed delay period, the~ the equipme~t is considered inoperable or the variable is considered outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon expiration of the delay period. If a Surveillance is failed within the d~lay periodj then the equipment is inoperable, or the variable is outside the specified limits and the Completion Times of the Requi-red--Acti ons "f.or the app n-eab 1e LCO ..Condi ti.ans b~gi n immediately upon the failure of the Surveillance~
Comp1e.tion of the Surveillance within the delay period allowed by this Specification, or within the Completion Ti.me of the ACtIONS, restores compliance with SR 3.0.1.
SR 3.0.4        SR 3,0.4 establishes the requirement that a1] applicable SRs must be met before entry fnto a MODE or other specified condition in the Applic~bility.
This Specification ensures that system and component OPERABILITY requirement~ and variable limits are met before entry into MODES or oth,er specified con-di ti ons in the Appl i cabi 1 i ty for which these systems and compo.nent.s ensure safe ope.ration of the unit. The provisions of this Specification sho.uld not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other s~ecified condition in the Applicability.
A provision is included to allow entry into a MODE or other specified condition in the Applicability when an LCO ts not met due to Surveillance not being met in accordance with LCO 3.0.4.                                -
con PBAPS UN IT 2                        B 3, 0-*14                      Revision No. 52
 
SR Appl i cabll ity B 3.0
* BASES SR  3'.0.4 (continued) lfawever, in certain ci rcumstancrns, f ai 7 i ng to meet an SR will not result in SR 3.0.4 restricting a MODE change or other specified condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(sJ are not required to be performed, per SR 3.0.1. which states that surveillances do not have to be performed on inoperable equipme,nt. When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(sJ since the requirement for the SR( s) to be performed is removed. Therefore, failing to perform the Survei 11 ance ( s) wi th1 n the specified Frequency does not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the Appl i cabi 1Hy.
However, since the LCO is not met in this instance, LCD 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes. SR 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Frequency, provided the requirement to declare the LCO not met has been delayed in accordance with SR 3.0.3.
The provisions of SR 3. 0. 4 sha 11 not prevent entry into MODES or other specified con di ti ons in the Appl i c.abi 1ity that are required to comply with ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other specified con di ti ans i_n the Appl i cabi Ji ty that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition -fn the Applicability associated w'ith tr.ansitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, and MODE 3 to MODE 4.
The prec.i se requirements for performance of SRs are specified such that exceptions to SR 3.0..4 are not necessary. The specific time frames and conditions necessary for meeting the SRs are specified in the frequency, in the S~rveillance, or both. This allows performance of Surveillances when the prerequisite condition(s) s~ecified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated LCD prior to the performance or completion of a Surveillance. A Surveillance that could not be performed until after entering the LCO's Applicability, would have its Frequency specified such that it is not "due'' until the specific co.nditi ans needed are met. Alternately, the Surveillance may be stated in the form of a Note, ~snot required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific formats of SRs' a nnot at i on i s f ound i n Sect i on 1. 4 , Freq uen cy .
* PBAPS UN IT 2                        B 3.0-15                          Revision No. 52
 
SOM B 3.1.1
* B 3 .1 REACTIVITY CONTROL SYSTEMS B 3. LI  SHUTDOWN MARGIN (SOM)
BASES BACKGROUND        SOM requirements are specified to ensure:
: a. The reactor can be made .subcri ti ca1 from a11 operating conditions and transients and Design Basis Events;
: b. The reactivity transients associated with postulated accident conditions are controllable within acceptable limits; and
: c. The reactor will be maintained sufficiently subcritical to preclude i.nadvertent critica11ty in the shutdown condition.
These requirements are satisfied by the control rods, as described in the UFSAR Section 1..5 (Ref. 1), which can compensate for the reactivity effects of the fue1 and water temperature changes experienced during all operating
* conditions.
* APPLICABLE        The- control rod -drop accident (CROA) analj~is- (Refs. 2 SAFffi ANALYSES  and 3r-assumes the core is subcriti.cal with the highest worth control rod withdrawn. Typically, the first control rod withdrawn has a very high reactivity worth and, should the core be critical during the withdrawal of the first control rod, the consequences of a CRDA coul'd exceed the fuel damage limits for a CRDA ( see Bases for LCO 3. I. 6, Rod R
Pattern ControP). Also, SDM is asswned as an initial condition for the control rod removal error during refueling (Ref. 4) and fuel assembly insertion. error during refueling (Ref. 5) accidents. The analysis of these reactivity insertion events assumes the refueling interlocks are OPERABLE when the reactor is in the refueling mode of operation. These interlocks prevent the withdrawal of more than one control rod from the core during refueling.
(Special consideration and requirements for multiple control rod withdrawal during refue.l ing are covered in Special Ope,rations LCO 3.10.6, nMult.iple Control Rod Withdrawal-Refueling.*) The analysis asstm1es this condition is acceptable since the core will be shut down with the hi.ghest worth control rod withdrawn, if adequate.
{continued)
PBAPS UNIT 2                        B 3.1-1                        Revision No,. O
 
SDM B 3.1.l
* BASES APPLICABLE SAFETY ANALYSES (continued)
SDM has been deDK>nstrated.. Prevention or mitigation of reactivity insertion events is necessary to limit energy depositfon in the fuel, to prevent signffi~ant fuel. damage, which coyld result 4n undue release of radioactivity.
Adequate. SOM ensure,s inadvertent critical ities and potential CRDAs involving high worth control rods (namely the first control rod withdrawn) wfll not cause significallt fuel damage.
SOM satisfies Criterion 2 of the NRC Policy Statement.
LCD            The specified SOM limit accounts for the uncertainty in the demonstration of SOM by testing. Separate SOM limits are provided for testing where the highest worth control rod is de.termined analytically or by measurement. This ts due to the reduced uncertainty in the SOM test when the highest worth control rod is detenntned by measurement. When SDH is demonstrated by calculations not associated with a test
{e.g., to conf1 rm SOM during the fuel 1oadi ng sequence),
additional margin is included to account for uncertainties in the calculation. lo ensure adequate SDM during, the design process, a design inargin is included to account for uncertainties in the design calculations (Ref. 6).
APPLICABILITY  In *MODES* 1 and 2, SOM IRUst be provided because subcrit1cality with the highest worth control rod. withdrawn is asswned in the CRDA analysis (Ref. 2). In MODES 3 and 4, SOM 1s required to ensure the reactor wi 11 be he1 d subcritical with margin for a single withdrawn control rod.
SDH is required in MODE 5 to prevent an open vessel, inadvertent criticality during the withdrawal of a single control rod from a core cell containing one or more fuel assemblies (Ref. 4) or a fuel assembly insertion error (Ref. 5} *.
ACTIONS        Ll With SOM not within the Hmits of the LCO in MODE 1 or 2, SDM must be restored within 6 hours. Fa i1 ure to meet the specified SDM may be caused by a control rod that cannot be inserted. The allowed Completion Tiine of 6 hours is f contjnued)
* PBAPS UNIT 2                        B 3.l-2                      Revision No. 0
 
SDM B 3.1.1
* BASES ACTIONS      AJ. (continued) acceptable~ considering that the reactor can still be shut down, assuming no failures of additional control rods to insert, and the low probability of an event occurring during this interval *
                .Ll:
If the SOM cannot be restored, the plant must be brought to MODE 3 H, 12 hours, to prevent the potential for further reductions in available SOM (e.g., additional stuck control
              -rods). The allowed C0111pletion Time of 12 hours is reasonable, based on operati.ng experience, te> reach MODE 3 from full powe.r conditiohs -in an orderly manner and without challenging plant systems.
Ll With SOM not within limits in MODE 3, the operator must i11J11ediately initiate action to fully insert all insertable control rods.. Action must continue until all insertable control rods are fully inserted. This action results in the least-reactive condition for the core-.
D..I, P,2, D.3, and P,4 With SDH not within limits in MODE 4, the operator must immediately initiate action to fully insert all insertable control rods. Action must continue until all insertable control rods are fully inserted. This action results in the least reactive condition for the core. Action must also be initiated wtthin 1 hour to provide means for control of potential radioactive. rel eases. ThiS includes ensuring secondary containment is OPERABLE; at least one Standby Gas Treatment (SGT) subsystem for Unit 2 is OPERABLE; and secondary containment i so1at i*Oh capability (i.e., at 1east one secondary containment i sol at ion valve and associated instrumentation are OJ>ERABLE, or other acceptable administrative controls to assure isolation capability), in each associated secondary containment penetration flow path not isolated that ts assumed to be isolated to mitigate radfoactivity releases. This may be performed as tcontjnued'l PBAPS UKIT 2                        B 3. l-3                    Revision No. O
 
SOM B 3.1.1
* BASES ACTIONS      0.1, D.2, D,3, and D,4 {continued) an administrative check, by examining logs or other information, to determine if the components are out of service for maintenance or other reasons. It is not necessary to perform the surveillances needed to demonstrate the OPERABILITY of the components. If, however, any required component is inoperable, then it must be restored to-OPERABLE status. In this case, SRs may need to be performed to restore the component to OPERABLE status.
Actions 111USt continue until all required components are OPERABLE.
E~l, E.2, E,3, E.4, and E,5 With SOM not within limits in MOD.E 5,. the operator must innediately suspend CORE ALTERATIONS that could reduce SOM, e.g., insertion of fuel in the core or the withdrawal of control rods. Suspension of these activtties shall not preclude completion of movement of a component to a safe condition. Inserting control rods or removing fuel from the core will reduce the total reactivity and are therefore excluded from the suspended actions.
Action llll.lst also be immediately initiated to fully insert all insertable control rods_ in core cells containing one or more fuel assemblies. Action must continue until all insertable control rods in core cells containing one or more fuel assemb1i es have been fully inserted. Control rods in core ce11 s contain i hg no fue 1 assemb11 es do not affect the
                -reactivity of the core and therefore do not have to be inserted.
Action must also be initiated within I hour to provide means for control of potential radioactive. rel,eases. This includes ensuring secondary containment is OPERABL[; at least one SGT subsystem for Unit 2 1S OPERABLE; and secondary containment isolation capability (i.e., at least one secondary containment isolation valve and as,soc:iated instrumentation are OPERABLE, or other acceptable administrative controls to assure isolation capability), in each associated secondary containment penetration flow path not isolated that is assumed to be isolated to mftigate radioactive releases. This may be performed as an
              -administrative check, by examining logs or other
{conti.nued)
PBAPS UNIT 2                      B 3. 1-4                      Revision No. 0
 
SDM B 3.1.1
* BASES ACTIONS        E.1, E.2, E.3, E.4, and E.5          (continued) information., to determine if the c;:9rciponents are out of service f'or maintenance or other r.easons.          It is, i:iot necessary to perform the SRs needed to demonstrate the OPERABILITY of the components.          If, however,    any requi:r;ed component is inope..r;able, then it must be restored to OPERABLE status.        In this ca~e, SRs mqy need to be p~~formed to restore the cornponeht to OPERABLE statu$. Actio_n must continue until all required cotaponents are OPERABLE, SURVE:I:LtANCE  SR  3.1. 1. 1 REQUIREMENTS Adequate SDM must be ve.r;.i,fied to ensucce that the reactot can be made subcritical &#xa3;rem any initial operating condition.
This can be accornpli*shed by a test, an evaluation, or a combination of the two. Adequate BDM is demonstrated before or during the first start.up after fuel moveme_nt or shuffling within the reqctor pressure vesselr or control rod replacement.      Control, rod replacement* refers to the decoupling and removal of a control rod from a core location, and subsequent replacement with a new control rod or a control rod from another core location.            Sihce core
                  -r.eacti-vi.ty wiJ.-1 .vary -during the c.yc1-e as a- f-uncu,on of--fuei depletion and poison burnup 1 the beginning ~f cycle (BOC) test must also account for, changes in co.re rea,ctivity during the cycle.      The,refore, to obtain the SDM, the initial measured vali:Je must be increased by an adcler, "R", which is the differenc;e between the calculated value of maxi.mum core reactivity during the operating cycle and the calculated BOC Core reactivity.        lf the value of R is neg.ative (tqat is, BOC ;[s tl:le most reac,tive point in the cycle), no correction to the BOC measured value is required (Ref. 3).              For the SDM demonstrations that rel.y solely on calc1.tlation of the highest worth control rod, additional margin (0.10%. Ak/k) must be added to the SDM limit of 0.28% Ak/.k to account for uncertainties in the calculation.
The SDM may be demonstrated during an in sequence control rod withdrawal, in which the highest worth control rod .is analytically determined, or during local critlc:als, where the highest worth contro.l rod is determinecl by testing.
Local critical tes.ts .require the withdrawal of out of (continued)
  *PBAPS UNIT 2                          B 3.1-5                        Revi.sion No. 72
 
SDM B 3.1.1 BASES SURVEILLANCE SR  3.1.1.1  (continued)
REQUIREMENTS seqUence control rods. This testing would therefore require bypassing of the Rod Worth Minimizer to allow the out of sequence withdrawal, and therefore additional requirements must be met (see LCO 3.10.7, "Control Rod Testihg-Operating") .
The Frequency of 4 hours after .reaching criticality is allowed to provide a reasonable amount of time to perform the requix:ed calculations and have appropriate verification.
During MODES 3 and 4, analytical calculation of SDM may be used to assure the requirements of SR 3.1.1.1 are met.
During MODE 5, adequate SDM is required to ensur.e that the reactor does not reach criticality during control rod withdrawals. An evaluation of each in vessel fuel movement during fuel loading (including shuffling fuel within the c0re) is required to ensure a,dequate SDM is maintained during refueling. This evaluation ensures that the intermediate loading patterns are bounded by the safety analyses for the final cor:e loading pattern. For example, bounding analyses that demonstrate adequate SDM for the most reactive configurations during the refueling may be
_performed to demonstrate acceptability of the entire fuel movement sequence. These bouhding analyses include adc;titional margins to the associated un:certainties. Spiral offload/reload sequences, inc;luding modified quadrant spiral offload/reload sequences, inherently satisfy the SR, provided the fuel assemblies are reloaded in the same configuration analyzed for the new cycle. Removing fuel from the Core will always result in an increase in SDM.
REFERENCES  1. UFSAR, Sections 1.5.1.8 .and 1.5.2.2.7.
: 2. UESAR, Section 14.o.2.
: 3. NEDE-24011-P-A, "General Electric Standard Application for Reactor E'Uel," latest approved revision.
: 4. UFSAR, Section 14 .. 5. 3 .3.
: 5. UFSAR, Section 14.5.3.4.
(continued)
* PBAPS UNIT 2                    B 3.1-6                    Revision No. 72
 
SDM B 3.1.1
* 'BASES REFERENCES (cont:inued)
: 6. UFS.AR, Section 3. 6. 5. 4 ..
* l?BAI'S UNIT 2                  B 3.1-7        .Revision No. 72
 
Reactivity Anomal1es B 3.1.2 B 3.1  REACTIVITY CONTROL SYSTEMS B 3.1.2  Reactivity Anomalies BASES BACKGROUND        In accordance with the UFSAR ( Ref. 1), reactivity shall, be controllable such that subcriticality is ,maintained under co1d conditions and.acceptable fue1 design limits are not exceeded durfng normal operation and abnormal operational t,ansients. Therefore, reactivity anomaly is used as a measure Of the predicted versus measured (~.e., monitored) core reacti~ity dUring power operation. A large reactivity anomaly could be the result of unanticipated changes in fuel reactivity or control rod worth or operation at conditions not consistent with those assumed in the predictions of core react1vity, and could potentially result in a loss of SOM or violation of acceptab1e fuel design limits. Comparing preoicted versus meas1:1red core reactivity supports the SOM demonstrations (LCO 3,1.1, "$HUTDOW.N MARGIN (SOM)") in assuring the reactor can be* brought safely to cold, subcrttical condHions.              *
* When the reactor core is critical or in normal power operation, a reactivity balance exists and the net reactivity is zero.. A comparison of pred.9 cted and measured reactivity is convenient under such a balance, since parameters .are being maintained relatively stable under steady state power conditions. The positive reactivity inherent in th. core design is balanc.ed by the negative reactivtty_of the control components. thermal f~edback, neutron leakage, and materials in the core that absorb neutrons, such as burnable i;Jb.sorbers, producing 2ero net reactivity.
In orde,r to achte.ve the required Juel cycle energy output, the uranium enrichment in the new fuel loadfng and the f~el loaded in the previous cycles provide excess positive reactivity b,eyond that required to sustain steady state operation at the beginning Of cycle (BOC). When the reactor is critical at RIP and ope rat, ng moderator temperature, the excess positive reactivity is compensated by burnable absorbers (e.g., g.adolinia), control ,rods, and whatever neutron poisons (mainly xeno~ and samarium) are pres~nt in the, fuel. The predicted core reactivity, as represented by
* PBAPS UNIT 2                            B 3.I-8                  Rvision No. 113
 
Reactiv1ty Anomalies B 3.1.2 BASES BACKGROUND      core kamctiva (k ff), is ca1culated by a 3D core simulator 0
(continued)  code as a function of cycle exposure. This calculation is performed for projected operating state.s and col'ilditi ons throughout the cycle. The monitored core k0 ff is calculated by the core monitoring system for attu.al plant conditions and is then compared to the predicted value for the cycle exposure.
APPLICABLE      Accurate prediction of core reactivity is either an explicit SAFETY ANALYSES ar implicit assumption in the accident analysis evaluations (Ref. 2). In particular, SOM and,reactivHy transients, such as control rod withdrawal accidents or rod drop accidents, are very sensitive to accurate prediction of core reactfvity. These accident analysis evaluations rely on computer codes that have been qualified .ag.ainst available test data, operating plant data, .and analytical benchmarks.
Monitoring reactivity anomal'y pro vi des additional assurarice that the r:iucl ear methods pro vi de an accurate re.presentation of the core reactivity, The. comparison between measured and predicted initial core reactivity provides a norm,alizatio*n for the calculationaT rno-del s u.sed to predict core reactivity. If the measured and predicted core k m,l for identical* core conditions at BOC dp 0
not reasonably a~.ree, then the assumptions used in the reload cycle design analysis or the calculation models used to predict core krit may not be. accurate. If reasonab1 e agre.ement between measured and predicted core reactivity exists at BOC, then the prediction may be norma.l i zed to the measured va Tue. Thereafter,. any significant deviations -rn the measured core keff from tha predicted core. kef.f tha.t develop during fuel depletion may be an indication that the
                .assumpt1ons of the DBA and transient analyses are no longer valid, or that an unexpected change in core con*ditions h.as occurred.
Reactivity anomalies satisfy Criterion 2 of the NRC Policy Statement.
LCD              Large differences between monitored and predicted core reactivity may i ndfcate that the assumptions of the DBA and transient analyses are no longer valid, or that the PBAPS UN IT 2                        B 3.l-9                    Revision No. 113
 
Reactivity Anomalies B 3.1.2 BASES LCO .        uncertainties in the "Nuclear Design Method~logy" are larger (continued) than expected. A limit on the difference between the monitored and the predi ctect core k fr of +/- 1% ~k/k has been 0
established based on engineering judgment. A> 1% deviation in reactivity from that predicted is larger than expected for normal operation and should therefore be eval u,ated. A deviation as large as 1% would not exceed the design conditions of the rea~tor and is on the safe side of the postulated transients.
APPLICABILITY In MODE 1, most of the control rods are withdrawn and steady state operation is typtcally achieved. Under these condttions, the comparison between predicted and monitored core reactivity provides an effective measure of the reactivity anomaly. In MObt 2, control rods are typically being withdrawn during a stijrtup. In MODES 3 and 4, all control rods are fully inserted and therefore the reactor is in the least reactiv~ state, where monitoring core reactivity ts not necessary. In MODE 5, fuel loading results in a continually changing core reactivity. SDM requirements (LCD 3.1.1) ensure that fuel movements are performed within the bounds of the safety analysis, and an SOM demonstration is required during the first startup following operations that could have altered tore reactivity (e.g., fuel movement, control rod replacement, shuffling),
The SOM test, required by LCD 3.1.1, provides a direct comp,arison pf the predicte.d and monitored core reactivity at cold conditions; therefore, reactivity anomaly is not required during these conditions.
ACTIONS      w Should an anomaly develop between measured and predicted core reactivity, the core reactivity difference*must be restored to within the limit to ensure continued operation is within the c0re design ass.umptions._ Restoration to within the limtt could be performed by an evaluatiQn of the c0re design and safety analysis to determine'the reason for the anomaly. T~is evaluation normall~ reviewi the core condit.i ons to determine ttiei r consistency* wi-th input :to design calculations. Measured core and pfocess parameters_
are also normally evaluated to determine that they .are within the bounds of the safety analysis, and safety analysis calculational_ models may be reviewed to veri.fy th'at they are adequate for representation of the cor~ conditions .
* PBAPS UN IT 2                    B 3.1-10                    Revision No. 94
 
Reactivity Anomalies B 3.1.2 BASES ACTIONS      A.....l  (continued)
The requfred Completion Time of 72 hours is based on the low probability of a OBA occurring during this periodJ and allows sufficient time to assess the physical condition of the reactor and complete tbe evaluatfon of the core design and safety analysis.
lL..l If the core reactivity cannot be restored to withi~ the 1% ~k/k limit, the plant must be brought to a MODE in which the LCO does not a'pply. To achieve this status, the plant must be brought to at least MODE 3 with1n 12 hours. The allowed Completton Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant SY!:items, SURVEILLANCE SR      3.1.2.1 REQUIREMENTS The core monitoring system calculate.s the core kaff for the reactor conditions -obtained from plant instrume,ntati-on. - A comparisDFl of the monitored core kett to the predicted core keft at the same cycle expos11r-e is used to cal cul ate tt,e reactivity difference, The comparison is required-when the core reactivfty has potentially changed by a significant amount. This may occur following a reftlelin,g i.n wMCh n,ew fuel assemblies are loaded, fuel assemblies are shuffled within the core, or control rods are replaced or shuffled.
Control rod replacement refers to the decouplir;ig and removal of a control rod from a cor~ location, and subsequent replacement with a new control rod or a control rod from another* core location. Also, core reactivity changes during the cycle. The 24 hour interval after reaching equiTi.brium conditions following a startup is based on the need for equilibrium xenon concentr,ations in the core, such that a.n accurate comparison betwee.n the moni tared and predicted core k~r can be made. For the purposes of this SR, the reactor is assumed to be at equilibrium conditions when steady .state operations (no control rod movement or core
* PBAPS UNIT 2                      B 3.1-11                  Re Vi s i On NO
* 113
 
Reactivity Anomalies B 3.1.2
* BASES SURVEILLANCE REQUIREMENTS SR 3.1,2.I    (continued}
flow changes) at c!:: 75% RTP .have been obtained. The .
1000 MWD/T Frequency was developed~ considering the relatively slow change in core reactivity with exposure and operating experience related to variations in core reactivity. The comparison requires the core to be operating at power levels which min:fmize the uncertainties and measurement errors,. in order to obtain meaningful results. Therefore, the comparison is only done when in MODE I.
REFERENCES    I. UFSAR, Section 1.5.
: 2. UFSAR, Chapter 14 .
* PBAPS UN IT 2'                  B 3.1-12                        Revision No. O
 
Control Rod OPERABILITY B 3. 1..3 B 3. I REACTIV'ITY CONTROL SYSTEMS
  ~  B 3. 1.3 Control Rod OPERABILITY BASES Control rods are components of the Control Rod Drive (CRD)
System, which is the primary reactivity control system. for the reactor. In conjunction with the Reactor Protection System, the CRD System provides the means for the reliable control of reactivity changes to ensure under conditions of normal operation, including abnormal operational transients, that specified acceptable fuel design* li.mits are not exceeded. In addition, the control rods provide the capabiltty to hold. the reactor core subctitical under all cohditions and to limit the potential amount and rate of reactivity increase caused by a malfunction in the CRD System. The CRD System is designed to satisfy the requirements specified in Reference I.
The CRD System consi.sts of 185 locking, piston control .rod drive mechanisms {CRDMs) and a hydraulfc control unit for each drive mechanism. The locking piston type CROM is a double acting hydraulic piston, which uses condensate water as the operating fluid. Accumulators provide additfonal energy fo.r scram. An index tube and piston, coupled to the control rod; are locked at fixed*-tncremehts* by -a-*collet ~
                        -mechanism. The collet fingers engage notches in the index..
tube to prevent unintentional withdrawal of the control rod, but without restricting insertion.
This Specification, along with LCO 3.1.4, *contrpl Rod Scram Times," and LCO 3.1.5, "Control Rod Scram Accumulators, n ensure that the perfonnance of the control rods in the event of a Design Basis Accident  (OBA) or transient meets the assumptions used ih the safety analyses of References 2t 3, and 4.
APPLICABLE          The analytical rnethods and assumptions used in the SAFffi ANALYSES      evaltiations involving control rods are presented in References 2, 3, and 4. The control rods provide the primary means for rapid reactivity control (reactor scram),
for maintaining the reactor subcr1tical and for limiting the po.tent1al effects of reactivity insertion events caused by malfunctions in the CRD System *.
{cont1nued)
* PBAPS  UNIT 2                        B 3.1-13                      Revision No. 0
 
Control Rod OPERABILITY B 3.1.3
* BASE'S APPLICABLE SAFETY ANALYSES (continued)
The capability to insert the control rods provides assurance that the assumptio.rfs for s.cram rea.ctivity in the OBA and tr,;insient analyses are not violated. Since the SOM. ensures the reactor will be subcriti cal w1 th the highest worth control rod Withdrawn (assumed single failure). the additional failure of a sec;:,ond control rod to insert, if re.qui red, could i nva.l i date the demonstrated SOM and potentially limit the ability of the CRO System to hold the reactor subcri ti cal . If the contro.l rod is stuck at an inserted position and becomes decoupled from the CRO, a control rod drop accident (CROA) can possibly occur.
Therefore, the requirement that a.l l control rods be OPERABLE ensures the CRD System can perform its ir;ite,nded funct10-n.
The control rods also protect the fuel from damage which could result ih rel:ease of radioactivity. The limits protected are the MCPR Safety Limit (SL) (see B.ases for SL 2.1.1, hReactor Core SLs" and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR) "), the. 1% cladding plastic strain fuel design limit (see Bases for LCO 3.2.3, "LINEAR HEAT GENERATION RATE CLHGR)"), an<l the fuel damage limit
                      ~see Bases for LCO 3.1.6, "Rod Pattern Control") during reactivity insertion events.
__ The r:1_egati v_e reacti.v-1-ty i ns!r'ti on- ( scram) p!"ovided by the CR  System provides the analytical basis for determi~ation of plant thermal liITTits and prov1des protection agair:ist fuel damage limits during a CRDA. The Bases. for LCD 3.1.4, LCD 3.1.5, and LCD 3.1.6 discuss in more detail how the Sls are protected by the CRO Sys.tern.
Control rod OPERABILITY satisfies Criterion 3 of the NRC Policy Statement.
LCO                The OPERABILITY of an individual control rod is based on a combination of factors, primarily, the scram insertion times, the control rod coupling integrity, and the ability to determine the E  ntrol rod position. Accumulator OPERAS I LITY is addressed by LCO 3 .1. 5. The associated scram accumulator status for a control rod only affects the scrim
                      'insertion times; therefore, an inoperable acc_umulator does not immediately require declaring a control rod inoperable, Althoug,h not all contro1 rods ,;ire required to be OPERABLE to satisfy the intended reactivity c;:0ntrol requirements, strict
* PBAPS UNIT 2                              B 3.1-14                              Re\lision No .. 49
 
Control Rod OPERABILITY B 3. 1.3
* BASES LCO          control over the number and distribution of inoperable (continued) control rods is required to satisfy the assumptions of the DBA and transient analyses.
APPLICABILITY In MODES 1 and 2, the control rods are assumed to function during a OBA or transient and are therefore required to be OPERABLE in these MODES. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requirements for control rod OPERABILITY during these conditions. Control rod requirements in MODE 5 are located in LCO 3.9.5, "Control Rod OPERABILITY-Refueling .. a ACTIONS      The ACTIONS Table is modified by a Note indicating that a separate Condition entry is allowed for each control rod.
Thts is acceptable, since the Requtred Actions for each Condition provide appropriate compensatory actions for each inoperable control rod. Complying with the Required Actions mayallow for continued operation, and subsequent inoperable control rods are governed by subsequent Condition entry and
* application of associated Required Actions.
A.I, A.2. A.3,  and  A.4 A con fro l rod is cons i de.red stuck if it will not insert by either CRD drive water or scram pressure (i.e., the control rod cannot be inserted by CRD drive water and cannot be inserted by scram pressure.) With a fully inserted control rod stuck, only th~se actions specified in Condition Care required as long as the control rod remains fully inserted.
The Required Actions are modified by a Note, whi~h allQWS the rod worth minimizer (RWM) to be bypassed if required to allow continued operation. LCO 3.3.2.1, *control Rod Block Instrumentation,a provides additional requirements when the RWM i-s bypas.sed to ensure compliance with the CRDA analysis.
With one withdrawn contra l rod stuck,. the l aca l scram reactivity rate assumptions may not be met if the stuck control rod separation criteria are not met. Therefo.re, a veri fi cation that the separation criteria. are met must be pe.rformed i11111ediately. The separation criteria are not met if a) the stuck control rod occupies a location adjacent to two *slow" control rods, b) the stuck control rod occupies a location adjacent to one "slow" control rod~ and the one
                *slow" control rod is also adjacent to another "slow*
control rod, or c) if the stuck control rod occupies a
* PBAPS UNIT 2                    B 3.1-15 (contjnued)
Revision No~ 2
 
Control Rod OPERABILITY B 3.1.3
* BASES ACTIONS        A,1, A.2, A,3, an-0 A.4        (continued) locatiqh adjacent to one "slow" contro7 rod when there is another pa1r of "slow" ccmtrol rods adjacent to O'he another.
The description of ~slow" control rods 1s provided in lCO 3.1.4, "Control Rod Scram Times." In addition, th,e associated control rod drive must be disarmed in 2 ho~rs.
The allowed Completfon Time of 2 hours is acceptable, considering the reactor can .still be shut down, assumir1g no additional control rods fail to insert, and provides a reasonable time to perform the Required Action in an orderly manner. The control rod must be i so1 ated from both scram and normal insert and withdfaw pressure. Isolating the control rod from s.cra*m and normal 1nsert and withdraw pressure prevents damage to the CROM. The control rod should be isolated from scram and normal insert and withdraw pressure, while maintaining cooling water to the CRO.
Monitoring of the insertion capabtl1ty of each Withdrawn control rod must also be performed within 24 hour~ from discovery of Condition A concurrent With THERMAL POWER greater than the low power setpo*i nt ( LPSP) of the RWM .
SR 3 .1. 3. 3. performs periodic tests of the control ro,d insertion capa.biltty of withdr-0'\!Jn control rods. Testing e.ach w*1thdrc:rwnc"on'trol
* ri5'd ensures-That-a gi::fr1ehc pro-bl em does-not exi~t~ This Completion Time also a1l~ws for an exception to the normal "time zero" for beginning the allowed .outage time "clock." The Required Actidn A.3 Campletion Time only pegins upon discovery o.f Condition A concurrent with THERMAL POWER greater than the actual LPSP of the RWM, since the notch insertions may not be compatible with the requirements of rod pattern control (LCO 3.1.6) and the RWM (LCO 3.3.2.1). The allowed Completion Time of 24 hours from disco~ery of Condition A concurrent with THERMAL POWER greater than the LPSP of the RWM pro vi des a reasonable time to test the control rods, considering the potential for a need to reduce power to perform th.e tests.
To allow continued operation With a withdrawn control rod stuck, an evaluation of adequate SOM is also required within 72 hours. Should a OBA or transient require a shutdown, to preserve the single failure criterion, an additional control rod would have to be assumed to fail to insert when requird. Therefore, the original SOM demonstration may not be valid. The SOM must therefore be evaluated (by measurement ar analysis) With the stuck control rod at its
* PBAfl'S UNIT 2                                                        Revision No. 79
 
Co.ntrol Rod OPERABILITY B 3.1.3
* BASES ACTIONS      A.l. A,2. A.3. and A.4 (continued) stuck position and the highest wnrth OPERABLE c0,ntrol rO'd assumed to be fully withdrawn.
The all owed Completion Time of 72 hours to verify SOM is adequate, considering that witti a single control rod stuck 1n a withdrawn position, the remaining OPERABLE control rods are capable of prov1ding the requi~ed scram and shutdGwn reactivity. Failure to reach MODE 4 is only likely if an additi o.hal control rod adj a cent to the stuck control rod also fails to insert durtng a required scram. Even with the postulated additirJnal single failure of an adjacent control rod to insert, sufficient reactivity control remains to reach and maintain Moot 3 conditions (Ref. 5 and 6) .
              .Ll With two or more Withdra.wn control rods stuck, the plant must be brought to MODE 3 wi th,i n 12 hours. 1he occurrence of more ~han one control rod stuck at a withdrawn position
* increases the probability that the reactor cannot be shut down if required. Insertion of all ir:isertable control rods eliminates the possibility of an additional failure of a control ~rod to insert. The allowed Completion T1me of 12 hours is reasonable, based on operating experience, t.o reach MODE 3 from full power conditions fn an orderly manner and without challenging plant systems.
c, 1 and  c. 2 With 0 ne or more contr*ol rods inoperable for reasons other 1
than being stuck in the withdrawn posit1on, (including a control rod which is stuck in the fully inserted position) operatton may continuej provided the control rods are fully inserted withjn 3 hours and disarmed (electrically or hydraulically) within 4 hours. Inserting a control rod ensures the shutdown and scram capabilities are not adversely affected. The control rod is disarmed-to p~event inadvertent withdrawal during subsequent operations. The control rods can be hydraulically <;fisarmed by closing the drive water and ex~aust water isolation valves. The control rods can be electrically disarmed by disconn_ecting power from all four directional control valve so.lenoids. Required Action C.1 is modified by a Note, which allows the RWM to be bypassed if requfred to al1ow insertion of the inoperable
* PBAPS UNIT 2                    B 3,1-17                      Revision No. 63
 
Control Rod OPERABILITY B 3.1.3
* BASES ACTIONS        C,1 and C,2    (continued) control rods and continued operation. LCO 3.3,2.1 provides additional requ1 rements w.hen the RWM is bypassed to ensure compliance with the CRDA analysis.
The allowed Completion Times are reasonable, considering the small number of allowed inoperable control rods, and provide time to insert and disarm the control rods in a~ orderly manner and without challenging plant systems.
0,1 and 0,2 Out of sequence control rods may increase the potential rea*ctivity worth of a dropped control rod during a CRDA. At
: ; : 10% RTP, the analyzed rod position sequence (Ref. 5 and 6) requ.i res inserted control rods not in compliance with the analyzed r,od position sequence to be separated by at least two OPERABLE control rods in all directions, including the diagonal. Therefore, if two or more inoperable control rods are not 1n compliance with the analyzed rod position
* sequence and not s~parated by at least two OPERABLE control rods, action must be taken to restore compliance with the analyzed rod position sequence or restore the control rods to OPERABLE status. Condition Dis modified by a Note indicating th.at the Condition is not applicable when
                > 10% RTP, since the analyzed rod position sequence is not required to be fol1ow~d under these conditions, as described in the Bases for LCO 3.1.6. The allowed Completion Time of 4 hours is acceptabJ e, considering the low probability of a CRDA occurr'irig .
                .L.l If any Required Action and associated Completion Time of Condit ion A, C, or D a re not met, or the.re a re nine. or more inoperable control rods, the pl ant must be brought to ,a MODE tn which the LCO does not apply. To achieve this status, the plant must be brought to MODE"3 within 12 hours. This
              *ensures all insertable control rods are inserted and places the reactor in a condttion that does not require the active function Ci .e., scram) of the control rods. The number of control rods permitted to be inoperable when operating above 10% RTP (e.g., no CRDA co.nsiderations) could be more than the value specified, but the occurrence of a large number of
* PBAPS UNIT 2                      B 3.1-18                    Revision No. 63
 
Control Rod OPERABILITY B 3.1.3
* BASES ACTIONS      .L..l    (continued) inoperaole control rods could be indicative of a generic problem, and investigation and re$olutfon of the potential problem should be undertaken. The allowed Completion Time of 12 hours ts reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging plant systems; SURVEILLANCE  SR    3.1.3.1 REQUIREMENTS The position of each control rod must be determined to ensure adequate information on control rod position is available to the operator for determining control rod OPERABILITY and controlling rod patterns. Control rod position may be determined by the use of OPERABLE position indicators, by moving control rods to a position with an OPERABLE indicator, or by the use of other appropriate methods. The Survei 11 ance Frequ.ency is controlled under the Surveillance Frequency Control Program.
SR 3.1.3.2 DELETED SR    3'.1.3.3 Control rod insertion capability is demonstrated by inserting each partially or fully withdrawn control rod at least one notch and observing that the control rod moves.
The control rod may then be returned to its original position. This ensures the control rod is not stuck and is free to insert on a scram signal. This Surveillance is not required when THERMAL POWER is less than or equal to the actual LPSP of the RWN, since the notch insertions rnay not be compatible with the requirements of the analyzed rod po s it i on s equen c e (L CO 3 . 1. 6 ) a nct t he RWM ( LC O 3 . 3 . 2 . 1 ) .
The Surveillance F'requency is controlled under the Surveillance Frequency Control Program. At any time, if a control rod -fs immovable, a
* PBAPS UN IT 2                          B 3.1-19                              Revision No. 86
 
Control Rod OP[RABILITY B 3.1.3
* BASES SUR.VE I lLANCE REQUIREMENTS SR  3,1.3.3    (contfnued) determination of that control rod's trippability (OPERABILITY) must be made and appropriate action taken.
For example, the unavailability of the Reactor Manual Control System does not affect the OPERABILITY of the control rods, provided SR 3.1.3.3 is current in accordance with SR 3 .. 0.2 ..
SR  3.1.3,4 Verifying that th:e sc-ram time for each control rod to notch position 06 is s 7 seconds provides reasonable assurance that the control rod will insert when required during a OBA or transient, thereby completing its shutdown function.
This SR is performed in conjunction with the control rod scram time testing of SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3,1.4.4. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1, PReactor Protection System (RPS)
Instrumentation," and the functional testing of SDV vent and
* drain valves in LCO 3.1.8, "Scram Discharge Volume (SDV)
Vent and Drain Valves," overlap this Surveillance to provide complete testing of the assumed safety function. The
                  - as_soci ated- Frequenci e.s are acceptable, consi deri r:,g t-fle more---
frequent testing performed to demonstrate other aspects of control rod OPERABILITY and operating experience, w~ich shows scram times do not significantly change over an operating cycle.
SR  3.1.3,5 Coupling veri f1 cation is performed to ensure the -control rod is connected to the CROM and will perform its intended function when necessary. The Surveillance requires verifying a control rod does not go to the withdrawn overtravel position. The overtravel position feature provides a positive check on the coupling integrity since only an uncoupled CRD can reach the overtravel position.
The verification is required to be performed any time a control rod is withdrawn to t'he "full out" position (notch position 48) or prior to declaring the control rod OPERABLE after work on the control rod or GRD System that could affect coupling (CRD changeout and blade replacement or complete cell disassembly, i.e .* guide tube removal). This includes control rods 1~sarted one notch and then returned PBAPS UN IT 2                          B 3.1-20                      Revision No. 79
 
Control Rad 0PERABIL1TY B 3.1.3
* BASES
  , SURVEILLANCE REQUIREMENTS SR 3,1.3.5 (continued) to th,e "full out" positi9n during the performance of SR 3.1.3.2. This Frequency is acceptable, considering the low probability that a control rod will become uncoupled when it is not befng moved and operating experience related to unc_ollp ling evi:;nts.
REFERENCES    1. UFSA R, Sect iO'n s L 5 . 1. 1 and l. 5
* 2
* 2 *
: 2. UFSAR, Section 14.6.2.
: 3. UFSA R, Append i x K, Se ct i on VI.
: 4. UFSAR, Chapter 14.
: 5. NED0-21231, "Banked Position Withdrawal Sequence,"
Section 7.2, January 1977.
: 6. NEDE-240H-P-A, "Genera,.] Electric Standard Applic:ation
* for Reactor Fuel," la test approved re.vision .
* PBAPS UN IT 2                    B 3.1-21                            Re.vision No. 63
 
Control Rod Scram Times B 3.1.4 B 3~1 REACTIVITY CONTROL SYSTEMS 13 3 .1. 4 Control Rod S.crant Ti mes BASES BACKGROUND          The scram function of the Control Rod Drive (CRD) System controls reactivity changes during abnonnal operational transients to ensure that specified acceptable fuel design limits are not exceeded (Ref. 1). The control rods are scranmed by positive means using hydraulic pressure exertep on the CRO piston.
When a. scram signal is: initiated, control air is vented from the scram valves, allowing them to open by spring action.
Opening the exhaust vahe .reduces the pressure above the main drive piston to atmospheric pressure, and opening the i.nlet valve applies the accumulator or reactor pressure to the bottom of the piston. Since the notches in the index tube are tapered on the lower edge, the collet fingers are forced open by cam action, allowing the index tube to move upward without restriction because of the high differentia1 pressure across the piston. As the drive moves upward and the accumulator pressure reduces below the reactor pressure, a ball check valve opens, letting the reactor pressure complete the scrai!I action. If the reactor pressure is low,
                    -sach as during startup,---the* accumulator-will* fully i:nse.rt the control **rod in, the required time without assistallce from reactor pressure.
APPLICABLE          The analytical methods and assumptions used in evaluating SAFffi ANALYSES    the control rod scram function are presented in References 2, 3, and 4. The Design Basis Accident {OBA) and transient analyses assume that all of the control rods scram.
at a specified insertiOn rate. The resulting negative scram
                    *reactivity forms the basis for the detennination of pl.ant thermal limits (e.g., the MCPR). Other distributions of scram times (e.g., several control rods scramming slower than the ave.rage time with several control rods scramming faste.r than the average time) can also provide sufficient scram reactivity. Surveillance of eac~ individual control rod's scram time ensures the scram reactivity assumed in the DBA and transient analyses can be met.
                                                                            <continued)
* PBAPS UNIT 2                          B 3.1-22                      Revision No. o
 
Control Rod Scram Times B 3.1.4
* BASES APPLICABLE      The scram function of the CRD System protects the MCPR SAFETY ANALYSES  Safety Limit (SL) (see Bases for SL 2.1.1, hReactor Core (continued)  SLs" and LCO 3 .. 2.2, "MINIMUM CRITICAL POWER RATJO CMCPR)")
and the 1% cladding plastic strain fuel design limit (see Bases fo.r LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"),
which ensure that no fuel damage w1l1 occur if these limits are not exceeded. Above 800 psig, the scram function is designed to insert negative reactivity at a rate fast enough to prevent the actual MCPR from becoming less than the MCPR SL, during the an,al'yzed limiting power transient. Below 800 psig, the scram function is assumed to perform during the control rod drop accident (Ref. 5) and, therefore, also provides protection against violating fuel damage limits during reactivity insertion accidents (see Bases for LCD 3.1.6, "Rod Pattern Control"). For the reactor vessel overrressure protection analysis, the scram function, along with the safety/relief va1ves, ensure that the peak vessel pressure is maintained within the applicable. ASME Code limits.
Control tod scram times satisfy Criterion 3 of the NRC Policy Statement .
LCO            The .scram times specif-fed in Table 3.1.4-1 (in the accompan~ing LCO) are required to ensure that the scram reactivity assumed in the OBA and transient analysis is met
( Ref. 6).
To accoti.nt for single failures a.nd "slow" Scramming control rods, the scram times specified in Table 3.1.4~1 are faster than those assumed in the design basis analysis. The scram times have a margin that allows up to approximately 7% of the control rods (e.g., 185 x 7% ~ 13) to have scram times exceed i ng the s pe c if i e d l i mits ( i . e . , " s l ow " cont ro l r o.d s )
assuming a single stuck control rod (as alJowed by LCO 3'.1.3, "Control Rod OPERABILITY") and an additional control rod failing to scram per the single failure criterion. The scram times are specified a.s a function of reactor steam dome pre~sure to account for the pressure dependence of the scram times. The scram times are speoified relative to measurements based on reed switch positions, which provide the control rod position indication. The reed switch closes ("pickup") when the d
* PBAPS UNIT 2                        B 3.1-23                                    Revision  No. 49
 
Control Rod Scram Times B 3 .1 .4
* BASES LC 0              index tube passes a specific location and then opens (continued)    (*dropout") as the index tube travels upward. Verification of the specified scram times in Table 3.1.4-1 is ,
accomplished through measurement of the *dropout" tfmes.
To ensuJ'le that loca1 scram t'eactivity rates are maintained within acceptable limits, no more than two of the all owed.
nslow" control rods may occupy adjacent locations.
Table 3.1.4-1 is madified by two Notes,. which state that control rods with scram times not within the limits of the table are considered "slow* and that control rods with scram times> 7 seconds are considered inoperable as required by
                    .SR 3. 1.3.4.
This LCO applies only to OPERABLE control rods since inoperable control rods will be inserted and disarmed
( LC0 3
* I. 3) . Sl ow scramming. cont ro1 rods may be conservatively declared inoperable. and not accounted. for as
                    *s1ow control rods.
11 APPLICABILITY      In HODES 1 and 2, a scram is assumed to function during transients and accidents analyzed for these p.lant conditions. These events are assumed to occur during
                --startup- and -power-*operat i on;-*"th*erefore';- the scram~funct ion -*
* of the control rods is required during the*se MODES~* In MODES 3 and 4, the control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block ts*.applied. This provides adequate requirements for contra l rod scram cap*abil i ty during these conditions.
Scram requirements in MOOE 5 ar.e contained in LC0 3.9.5, "Control Rod 0PERABlLITY--Refueling.
* ACTIONS          AJ.
When the requirements of this tco are not met, the rate of negative reactivity insertion during a scram may not be within the assumptions of the safety analyses. Therefore, the plant Qlust be brought to a MODE i'n which the LCO does not apply. To achieve this status, the plant must be brought to MOOE 3 within 12 hours. The allowed Completion Tillle of 12 hours is reasonable, based on operati.ng experience, to reach MODE 3 frODI full power conditions in an orderly manner and without challengi.ng plant systems.
(continued)
PBAPS UNIT 2                            B 3.1-24                        Revision No. 0
 
Control Rod Scram Times B 3.1.4
* BASES    (continued)
SURVEILLANCE REQU I REMEN'TS The four SRs of this LCO are modified by a Note stating that during a single control rod scram time surveillance, th,e CRD pumps shall be isolated from the associated scram accumulator. With the CRD pump isolated, (i.e., charging valve closed) the influence of the CRD pump head does not affect tl:ie single control rod scram times. During a full core scram, the CRD pump head would be seen by all control rods and would have a negligible effect on the scram insertion times.
SR 3.1.4.1 The scram reactivity used in OBA and transient ana1yses is based on an asswned control rod scram time. Measurement of the scram times with reactor steam dome pr~ssure ~ 900 psig demonstrates a.cceptabl e scram times for the transients analyzed in References 3 and 4 .
                      .Maximum scram insertion times occur at a reactor steam dome pressure of approximately 800 psig because of the competing effects of reactor steam dome pressure and stored accumulator energy. l:herefore, demonstration of adequate scram times at reactor steam dome pressure;,: 800 psig ensures that the measured scram times wil1 be within the specified -1 ~ mits at- higher --f)ressures. -Limits-.are -spe-ifi ed as a functiori of reactor pressure to account for the sensitivity of the scram insertion times* with pressure and to a11 ow a range of pressures over which scram time testi*ng can be performed. T~ ensure that scram time testing is performed within a reasonable time after a shutdown
                      ~ 120 days. or l anger, all control rods a re re qui red to be tested before exceeding 40% RTP. This Frequency i _s acceptable considering the additional surveillances performed for control rod OPERABILITY, the frequent verification of adequate accumulator pressure, and the required testing of control rods affected by fuel movement within the ass_ociate core cell and by work on control rods or the CRD System.
SR  3_,1.4.2 Additional testing of a sample of control rods is required to verify the continued performance of the scram function during the cycle. A representative sample contains at leqst 10% of the control rods. The sample remains representative
* PBAPS UN IT _2                            B 3 .1-25 (continued)
Revision No. '57
 
Control Rod Scram Times 8 3.1.4
* BASES
  ~-----------------------~-------~----
SURVEILLANCE    SR 3,li4,2    (continued)
REQUI 1?.EMENTS if no more than 7.5% of the control rods in the sample tested are determined to be "slow''. With mot~. than 7.5% of the sample declared to be "slow" per the criteria fn Table 3.1.4-1., additional control rods are tested until this 7.5% criterion (i.e., 7.5% of the active sample size) is satisfied, or until the total number of ''slow" control rods (throughout the core, from all .Surveil1ances) exceeds the LCO limit. For planned testing, the control rods selected for the sample sh,oul d be different for each test. Data from.
in.advertent scrams should be used whene\ler poss1&deg;ble to avo-id unnecessary testing at power, even if the control rods with
                  <lata may have been prevrously tested in a sa,mple. The Surveillance Frequency is rnntrolled under the Surveillance Frequency Control Program.
SR    3.1.4.3 When work that could affect the scra~ insertion time is performed on a control rod or the CRD System, testing must
* be done to demonstrate that each affected control red retains adequate scram p.erformc;rnce over the range of applica~le reactor pressures fro0 zero to the maxim&#xb5;~
pefmisiible ~ressur~. This surveillance can be met by performance of eiiher scram time testing or Diaphragm Alternative Response Ti me ( DART) testing" when it is concluded that DART te~ting monitors the performa11ce of all aff ecte*d components. The test 1ng must be performed once before declaring the control rod OPERABLE. The required testing must demonstrate the affected control rod is still within acceptable limits. The limits for reactor pressures
                  < 800 psig are established based on a high probability of meeting the acceptance criteria at reactor pressures~ 800 psig. limits for 2:: 8{)0 psig are found in Table 3.1.4-1. If testing demonstrates the ijffected control rod does not meet these limits, but is within the 7 second limft of Table 3 .1. 4-1, Note 2 1 the co:ntrol rod can be declared OPERABLE.
and "slow."
* PBAPS UNIT 2                        B 3.1-2fr                    Revision No. 86
 
Control Rod Scram Times B 3.1.4
* BASES SURVEILLANCE REQUIREMENTS SR 3.1,4 .* 3 (continued)
Spe'Cific examples of work that could affect the scram times are (but are not limited to) the followingt removal of any CRD fot' maintenance or modification; replacement of a control rod; and maintenance or modification of a .scram solenoid pilot valve, scram valve, accumulator, isolation v~lve or ~heck valve in the piping required for scram.
The Fre.que.ncy of once prior to dechring the affected control rod OPERABLE is atceptab1e because of the capability to test the control rod over a range of operating conditions and the more frequent surveillances on other ispects of control rod OPERABILITY.
SR 3.1.4.4 When work that could affect the scram insertion time is performed on a control rod or CRD System, or when fuel movement within U1e reactor vessel occurs testing must be done to demonstrate ea.ch affected control rod is sti 11 within the 1imits of Table 3 .1.4-1 with the reactor steam dome pressHre ~ 800 psig. Where work has been performed at high reactor pressure, the requirements of SR 3.1.4,3 and SR 3.1~4.4 can be satisfied with one test. For a control rod affected by work performed while shut down, however, a zero pres.sure and high pressure test may be required.. This testing ensures that, prior to wi thdrawi rig the control roo for continued opera ti on, th-e ~ontro l rod scram pe.rformance is acceptable for operating reactor pressure conditions.
Alternative.ly~ a control rod scram test during hydros.tatic pres.sure testing could also satisfy both criteria. When fuel movement occurs within the reactor pressure vessel, only those control rods associated with the cor~ calls affected by the fuel moNement are required to be scram time tested. During a routine refueling outage, it is expected that a1l control rods will be affected.
The Frequency of once prior to exceeding 40% RTP is acceptable because of the capability to test the control rod over a range of operating conditions and the more frequent surveillances on other aspects of control rod OPERABILITY.
REFERENCES    1. UFSAR, Sections 1.5.1.3 and 1.5'.2 .2.
* PBAP$ UN IT 2
: 2. UFSAR, Section 14.6.2.
B 3.1-27 d
Revision No. 57
 
Control Rod Scram Times B 3.1.4
* BASES REFERENCES
( continued)
: 3. UFSAR, Appendix K, Section VI.
: 4. UFSAR, Chapter 14.
: 5. NEDE-2~011-P-A, "General Electric Standard Application for Reactor Fuel, 11 latest approved revision.
: 6. Letter from R. E. Janecek (BWROG) to R. W. Starostecki (NRC), "BWR Owners Group Revised Reactivity Control System Technical Specifications," BWROG-8754, September 17, 1987 .
* PBAPS UNIT 2                  B 3.1-28                      Revision No. 72
 
Control Rod Scram Accumulators B 3.1.5
* B 3.1 B 3.1.5 REACTIVITY CONTROL SYSTEMS Control Rod Scram Accumulators BASES BACKGROUND          The control r0d scram accumulators are. part of the Control Rod Drive (CRD) System and are provided to ensure that the control rods scram under varying reactor conditions. The control rod scram accumulators store sufficient energy to fully insert a control rod at any reactor vessel pressure, The accumulator is a hydraulic cylinder With a free floating piston. The piston .sepa.rates the wate.r used to scram the control rods from the nitrogen, which provides the required energy. The scram accumulators are necessary to scram the control rods within the required insertion times of LCO 3.1.4, "Control Rod Scram Times."
APPLICABLE          The analytical methods and assumptions used in evaluating SA!=ETY ANALYSES    the control rod scram function are presented in References 1, 2, and 3. The Design Basis Accident (OBA) and transient analyses assume that all of the control rods scram at a specified insertion rate. OPERABILITY of each individual control rod scram accumulator, along with LCO 3.1.3, "Contr,ol Rod OPERABIUTY," and ,LCD 3.1.4, ensures that the scram reactivity assumed in the OBA and transient analyses can be met. The existence of an 1noperable accumulator may invalidate priors-cram time measurements for the associated control rod.
The scram function of the CRD System, an~ therefore the OPERABILITY of the accumulators, protects the MCPR Safety Limit (see Bases for SL 2.1.1, "Reactor Core SLs" and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)") and lZ cladding plastic strain fuel design limit (see Bases for LCO 3.2.3, "LINEAR HEAT GENERATION RATE CLHGR)"), which ensure that no fuel damage will occur if these limits are not exceeded ( see Bases for LCO 3 .1. 4). In a,dditi on, the scram function at low reactor vessel pressure (i ,e., startup conditions) provides protection against violating fuel design limits during reactivity insertion accidents (see Bases for LCD 3.1.6, "Rod P.attern Control").
Control rod scram accumulators satisfy Criterion 3 of the NRC Policy Statement.
(continued)
PBAPS UN IT 2                          B 3.1-29                      Revision No. 49
 
Control Rod Scram Accumulators B 3.1.5
* BASES  (continued)
LCD                The OPERABILlTY of the control rod scram accumulators is required to ensure that adequate scram tnsertion capability exists when needed over the entire range of reactor pressures. The OPERABILITY of the scram accwnulators is based on maintaining adequate accumulator pressure.
APPLICABILITY        In MODES 1 and 2, the scram function is required for mitigation of DBAs and transients, and therefore the scram accU111Ul ators must b:e OPERABLE to support. the scram fun ct 1on ..
In MODES 3 and 4, control rods are not abl'E! to be withdrawn since the reactor 1110de switch is in shutdown and a.control rod block 1s applied. This provides adequate requirements for control rod scram accumulator OPERABILITY during these conditions. Requirements for scram accumulators in HOOE 5 are contained 1n LCO 3.9.S, *control Rod OPERABILITY-Refueling."
ACTIONS            The ACTIONS Table is modif1.ed by a Note 1ndicatfog that a separate Condition entry is allowed fo.r each control rod scram accumu,lator. This is acceptable since the Required.
* Acttons for each Condition provide appropriate compensatory actions for each inoperable accumulator. Complying with the Required Actions may allow for continued operatfon and subsequent inoperable *acc;U111Ul ato*rs governed by subseqiie11t Condition entry and appltcation of ass*ociated Required Actions.
* A.I and A.2 With one control rod scram accumulator inoperable and the reactor steam dome pressure~ 900 psig, the control rod may be declared "slow,* since the control rod wil1 still scram at the reactor operating pressure but may not .satisfy the r~quired scram times in Table 3.1.,4-1. Required Action A.I is _modified by a Note indicating that dec.laring the control rod *s1ow* only applies if the associated control scram time was within the limits of Table 3.1.4-1 during the last scram time test. Otherwise, the control rod would already be considered
* s1* ow* and the further degradation of scram performance wfth an inoperable accUD1ulator could result in excessive scram tilles. In this event, the associated
{conti"nuedl
* PBAPS UNIT 2                            B 3.1-30 "                      Reviston No. 0
 
Control Rod Scram Accumulators B 3.1.5
* BASES ACTIONS      A.I and A,2    (continued) control rod is declared inoperabl.e (Required Action A. 2) and LCO 3.1.3 is entered. This would result in requiring the affected control rod to be fully inserted and disarmed, thereby satisfying its intended function, in accordance with ACTIONS of LCO 3.1.3.                    .
The allowed Completion Time of 8 hours is reasonable, based*
on the large number of control rods available to provide the scram function and the ability of the affected control rod to sctam only with reactor pressure at high reactor pressures.
8.1. B.2.1~ and B,2.2 With two or more control rod scram accumulators inoperable and reac::tor steam dome pressure~ 900 psig, adequate pressure ntust be supplied to the charging water header.
With inadequate charging water pressure, all of the accumulators could become inoperable, resulting in a potentially severe degradation of the scram perfonnance *.
Therefore, within 20 minutes from discovery of charging
  . I              water-..header pressure< 940 psig concurrent.with Condition B, adequate charging water header pressure must be restored. The allowed Co_mpleti.on Time of 20 minutes is reasonable, to place a CRD pump into service to restore the charging water header pressure, if required. This Completion Time is based on the ability of the reactor pressure alone to fully insert all control rods.
The control rod may be dec1ared *slow,* since the control rod will still scram using only reactor pressure, but may not satisfy the times in Table 3.1.4-1. Required Action B.2.1 is modified by a Note indkating that declaring the control rod *slowH only applies if the associated control scram time is within the limits of Table 3,.1.4-1 during the last scram time test. Otherwise, the control rod would already be considered *slown and the further degradation of scram performance with an inoperable accwnulator could result in excessive scram times. In this event, the associated control rod is declared inoperable (Required Action B~2.2) and LCO 3,1.3 entered. This would
                                                                      <continued)
* PBAPS UN ll 2 1
Revision No. 2
 
Control Rod Scram Accumulators B 3.1.5
* BASES ACTIONS        B.1, B.2.L and B.2,2 (continued}
result in requiring the affected control rod to be fully inserted. and disarmed; thereby .s:at i sfyi ng 1ts intended function in accordance with ACTIONS of Leo 3.1.3.
The allowed Completion lime of 1 hour is reasonable, based on the ability of only the reactor pressure to scram the control rods and the low probability of a DBA or transient occurring While the affected accumulators are inoperable.
C.l and C.2 With one or more control rod scram accumulators tnoperable and the reactor steam dome. pressure < 900 psig, the pressure supp]ied to the charging water header must be adequate to ensure that accl,111lul ators rerna in charged.. Wi'th the reactor steam dome pressure < 900 ps ig., the funct 1on of the accumulators in providing the ~cram force becomes much more important since the scram function could become severely degraded during a depressurization event or at low reactor
* pressures. Therefore,. i11111ediately upon discovery of charging water header pressure < 940 psig, concu.rrent with Condttton C_, _all cQntrol rods* a.ssociat~d _wi_th i.npperable
_ ac.cumul ators must be* veri-fi ed to be fully inserted.
Withdrawn control rods with inoperable accumulators may fail to scram under the.se* low pressure conditions. The associated control rods must al so .be dec.1 ared i noperapl e within 1 hour. The allowed Completion Time of 1 hour is reasonable for Required Action C.. 2, considering the low probability of a OBA or transient occurring during the time that the accW11ulator is inoperable.
The reactor mode switch must be i11111ediately placed in the shutdown position if etther Required Action and associated Comple.tion Time associated witn the loss of the CRD charging pump (Required Actions B.l and C.l) cannot be met. This ensures that all insertable control rods are inserted and that the reactor is in a condition that does not require. the (continued)
* PBAPS UNIT 2                      B 3.1-32                          Revision No .. 2
 
Gor:itrol Rod Scram Accumulators B 3.1.5
* BASES
  ------------------~----~----------~--
ACTICTNS      .lhl.  (continued) active function Ci .e., scram) of the- .control rods. This Required Action is modified by a Note stating that the action is not applicable if all control rods associated With the inoperable scram ac~umulators are fully inserted, since the function of the control rods has been performed.
SURVEI LlANCE  SR  3,1.5,1 REQUIREMENTS SR 3.1.5.1 requires that the accumulator pressure be pertodical ly checked tD ensure a*ctequate accumulator pressure exists to provide sufficient scram force, The primary indicator ~f accumulator OPERABILITY is the accumulator pressure. A minimum accumulator pressure is specified, below which the capability of the accumulator to perform its intended function becomes degraded and the accumulator is considered inoperab1e. The minimum accumulator pressure of 940 pstg is wel1 below the expected pressure of approximately 1460 psig (Ref. 1). Declaring the accumulator inoperable when the minimum pressure is not maintained ensures that
* REFERENCES significant degradation in scram times does not occur. The Surveillance Frequency is controlled under the Surveillance Freque.ncy Control Program .
: 1. UFSAR, Section 3.4.5,3 and Figure 3.. 4.10.
: 2. UF-SAR, Appendix K, Section VI.
3,    UFSAR, Chapter 14 .
* PBAPS UN IT 2                                                    Revision No. 86
 
Rod Pattern Control B 3.1.6
* B 3.1 B 3.1.6 BASES REACTIVITY CONTROL SYSTEMS Rod Pattern Control
  .BACKGROUND        Control rod patterns during startup conditions are controlled by tne operator and the rod worth minimizer (RWH)
(LCO 3.3.2.1, "Control Rod Block Instrumentation"), so that only specified control rod sequences and relative positions are all owed over the operating range of all control rods inserted to 10% RTP, The sequences limit the potential amount of reactivity addition that could occur in the event of a Control Rod Drop Accident (CRDA).
Thia Specification assures t~at the control rod patterns are consistent with the assumptions of the CRDA analyses of References 1 and 2.
APPLICABLE          The analytical methods and assumptions used in evaluating SAFETY ANALYSES    the CRDA are summarized in References 1 and 2. CRDA analyses assume that the reactor operator follows prescribed
* withdrawal sequences. These sequences define the potential 1n1t1al conditi ans for the CRDA analysis. The R\.tJt:1 (LCO 3.3.2.1) provides backup to operator control of the withdrawal sequences to ensure that the 1n1ti al oond1t1ons of the CRDA analysis are not violated.
Prevention or mitigation of positive reactivity insertion events is necessary to 1-frnit the energy deposition 1n the fuel, thereby preventing significant fuel damage which could result 1n the undu_e rel ease of radi oacti v1ty. Si nee the failure consequences for U02 have been shown to be 1nsign1ficant below fuel energy depositions of 300 cal/gm (Ref. 3), the fuel damage limit of 280 cal/gm provides a
                      ~argin of safety from significant core damage which would result in release of radioactivity (Refs. 5). Generic evaluations (Refs. 1 and 6) of a design basis CRDA (i.e., a CRDA resulting in a peak fuel energy deposition of 280 cal/gm). have shown that if the peak fuel enthalpy remains below 280 cal/gm, then the maximum reactor pressure will be less than the required ASME Coct'e limits (Ref. 7) and the calculated off site doses wi 11 be well within the required limits (R&f. 5).
{continued)
* PBAPS UNIT 2                          B 3.1-34                      Revision N0. 75
 
Rod Pattern Control B 3.1.6
* BASES APPLICABLE SAFETY ANALYSES Control rod patterns analyzed in Reference 1 follow the analyzed rod position sequence. The analyzed rod position
( cont i hued) sequence is applicable from the conditi0n of all cor;itrol rods folly inserted to 10% Rn (Ref. 2). For the analyzed rod posit 1on sequence, t h,e control rods a re requ:fred to be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions. Th'e banked positions are established to mtnimtze the maximum incremental contro1 rod worth without being overly restrictive during normal plant operatfon. Generic analysis of the analyzed rod,position seque.nce (Ref. 1) has demonstrat~d that the 280 ca]/gm fuel damage limit will not be violated during a CRDA whife following the analyzed rod position sequence mode of operation. The generic analyzed rod position sequ,ence analysis (Ref. 8) also evaluates the effect of fu1ly inserted, inoperable control rods not tn compliance with the sequence, to allow a limited number (i.e., eight) and distribution of fully inserted, inoperable control rods.
When performing a shutdown of the plant, an opti0nal rod position sequence (Ref. 9) may be u~ed provided that all withdrawn control rods have been confirmed to be coupled.
The rods may be inserted without the need to stop at intermedfate positions since the possibility of a CRDA is.
eliminated by the tonfirmation th~t withdrawn control rods are coupled. When using the (Ref. 9) control rod sequence for shutdown, the RWM may be reprogrammed to enforce the requirements of the improved control rod insertion process, or may be bypassed and the analyzed rod position sequence implemented under LCO 3.3.2.1, Condition D controls.
In order to use the Reference 9 shutdown proces~. an extra cM.ck is .requtred in order to consider a co,ntrol rod to be "confirmed" to be coupled. This extra check ensures that no single operator err0r can result in an incorrect coDpling check. For purposes of th'i s shutdown process, the method for confirming that control rods are coupled varies depending on the position of the control rod in the core. Detail on this cou.pling confirmation requirement are provided in Reference 9. If the requi rem.ents for use of the control rod insertion process contained in Reference 9 .:1re followed, th.e plant is considered in compliance with the rod position sequence as required oy Leo 3.1.6.
Rod pattern control satisfies Criterion 3 of the NRC Policy Statement .
* PBAPS UNIT 2                      B 3.1-35
                                                                            ~continued)
Re vi s i on No . 114
 
Rod Pattern Control B 3.1.6
* BASES LCO (continued)
Compliance with the prescribed control rod sequences minimizes the potential consequences of a CRDA by limiting the initial conditions to those consistent with the analyzed rod position sequence. This LCO only applie:s to OPERABLE contro7 rods. For inoperable control r0ds required to be inserted. separate requirements are specified in LCO 3.1.3.
                      "Control Rod OPERABILITY," consistent with the allowances for inoperable control rods in the analyzed rod position sequence.
APPLICABILITY      In MODES 1 and 2, when THERMAL POWER is~ 10% RTP, the CRDA is a Design Basis Accident and, therefore, compliance with the assumptions of the safety analysis is required. When THERMAL POWER is> 10% RTP, there is.n0 credible control rod configuration that results in a control rod worth that rnuld exceed the 280 cal/gm fuel damage limit during a CRDA (Ref. 2). In MODES 3, 4, and 5, since the reactor is shut down and only a single control rod can be withdrawn from a core eel] containing fuel assemblies, adequate SOM ensures that the consequ-ences of a CRDA ar,e acceptable, since the reactor will remain subcritical with a single control rod withdrawn.
(continued)
* PBAPS UN IT 2                        B 3.l-35a                    Revision No. 63
 
Rod Pattern Control B 3. 1.6
* BAS ES ACTIONS
( con t i nue d )
A.1 and 1i;.2 With one or more OPERABLE control rods not in compliance with the analyzed rod position sequence, actions may be taken to either correct the control rod pattern or declare the associated control rods inoperable within 8 hours.
Noncompliance with the prescribed sequence may be the result of "double notching," drifting from a control rod drive cooling water transient, leaking scram valves, or a power reduction to s 10% RTP before establishing the correct control rod pattern. The number of OPERABLE control rods not in compliance with the prescribed sequence is limited to eight, to prevent the operator from attempting to correct a control rod pattern that significantly deviates from the prescribed sequence. When the control rod pattern is not in compliance with the prescribed sequence, all control rod movement must be stopped except for moves needed to correct the rod pattern, or s6ram if warranted.
Required Action A.l is modified by a Note which allows the RWM to be bypassed to allow the affected control rods to be
* returned to their correct position. LCO 3.3.2.1 requires verification of control rod m0vement by a second licensed operator or a qualified member of the technical staff (i.e.,
personnel trained in actordance with an approved training program). This ensures that the control rods will be moved to the correct position. A control rod not in compliance with the prescribed sequence is not considered inoperable except as required by Required Action A.2. The allowed Completion Time of 8 hours is reasonable, considering the restrictions on the number of allowed out of sequence control rods and the low probability of a CRDA occurring during the time the control rods are out of sequence.
B.l and B.2 If nine or more OPERABLE control rods are not in compliance with the analyzed rod position sequence, the control rod pattern significantly deviates from the prescribed sequence.
Control rod withdrawal should be suspended immedfately to prevent the potential for further deviation from the prescribed sequence. Control rod insertion to correct control rods Withdrawn beyond their allowed position is allowed since, in general, insertion of control rods has
* PBAPS UN IT 2                              B 3.1-36                    Revision No. 63
 
Rod Pattern Control B 3, 1 ,6
* BASES ACTIONS      B,1 and B.2      (continued) less ,mp.act on control rod worth than w-rthdrawah have.
Require~ Action B.1 is modified by a Note which allows the RWM to be bypassed to a~low the affected control rods to be returned to their correct posftion.
LCD 3.3.2.1 requires verification of control rod movement by a setond licensed operator or a qualified member of the technical staff.
When nine or more OPERAUE control rods a re not in compltance with the analyzed rod position sequence, the reactor mode switch must be placed in the shutdown position within l hou.r. With the mode switch in shutdown, the reactor is ~hut down, and as such 1 does not meet the applicability requirements of this LCD. The allowed Completion Time of 1 hour is reasonable to allow insertion of control rods to restore complianca, and is appropriate relative to the low probability of a CRDA occurring with the control rods out of sequence.
SURVEI LLANGE SR 3.1.6.1 REQUIREMENTS The control rod pattern is periodically verified to be in comp 1i an ce wi_ th J.he a na 1y zed_ rod pos_it i qn s tquence to en sure the assumptions of the CRDA ana1y$es are met. The Survei 71 ance Frequency is control~ ed u,nder the Survei 11 ance Frequency Control ProgNcfll. The RWM provides control rod blocks to enforce the required sequence and is required to .be.
OPERABLE when operating at s 10% RTP.
REFERENCES    1. NfDE-24011-P-A, "Generar Electric Standard Applicatfon for Reactor Fuel," latest approved revision.
: 2. Letter (BWROG-8644) from T. Pickens CBWROG) to G. C.
Lainas (NRC), ~Amendment 17 to General Electric Licensing Topical Repo,rt :NEDE-24011-P-A."
: 3. UFSAR, Section 14.6.2.3.
: 4. Deleted.
5*    l O CFR 5 0
* 6 7 .
* PBAPS UN IT 2                        S. 3.1-37                          Revision No. 86
 
Rod Pattern Contror B .3,1.6
* BASES
  --~-----------~------------~-------
REFEREN,CES        6. NED0-21778-A,  "Transient Pressure Rises Affected
( co.n t i nued )    Fracture. Toughness Requirements for Boiling Water Reactors," December 1978.
: 7. ASME, Boiler and Pressure Vessel Code.
: 8. NED0-212.31, "Banked Position Withdrawal Sequ,ence,"
January 1977.
: 9. NEDD~3309l~A, urmproved BPWS Control Rod Insertion Process," Revision 2, July 2004 .
* PBAPS UNIT 2                        B 3.1-38                    Revision No. 61
 
SLC SY,Stem B 3.1.7
* B 3.1 B 3.1.7 REACTIVITY CONTROL SYSTEMS Standby Liquid Control (SLC) System BASES BACKGROUND        The SLC System is desfgned to provide the capability of bringing the reactor, at any time in a fuel cyclej from full power and minimum control rod inventory (which is at the pe,ak of t he xenon t r a ns i e nt ) t o a s ubc r it i ca l con dit i on w1 t h t he reactor in the most reactive, xenGn free state without taking credit for control rod movement. The SLC System satisfies the requirements of 10 CFR 50.62 (Ref. 1) on anticipated tr*ansient without scram using highly enriched boron. Using highly enriched boro,n in the SLC System increases the rate of
                    ~oron-10 injection and functions to ~hutdown th~ reactor core faster. This limits the heat generated that is transferred to the suppression pool during an ATWS event. Limiting the heat transferred to the suppression pool maintains the pool below design limits, which ensures adequate net positive suction head (NPSH) is available for the emergency cote cooling system ( ECCS) pumps without credit for cont a i.nment accident pressur*e .
The SLC System is also* used to maintain suppression pool pH at or above 7 following a loss of ooolant accident (LOCA) involving significant fission product releases. Maintaining suppression pool pH levels at or above 7 following an accident ensures that sufficient iodine Will be retained in the suppression pool water, Reference 1 requires a SLG' System with a minimum flow capacity and boron content equivalent in control cap~city to 86 gpm of 13 weight percent sodium pentabora.te solution.
Natural .sodium pentaborate solution is 19.8% atom Boron~lO, Therefore, the system parameters of concern. boron concentration (C), SLC pump flow rate (Q), and Boron-10 enrichment (E), may be expressed as a multiple of ratios.
The expression is as follows:
C                    Q                    E
_____ x _____ x _ _ _ __
13%' weight            86 gprn          19.8% atom If the product of this expression is~ 1, then the SLC System satisfies the criteria of Reference 1, As sue~. the product of this expre~sion at the minimum acceptance (continued)
PBAPS UN IT 2                          B: 3 .1-39                              Revis.ion No. 114
 
SLC Syst~m B 3 .1.7
* BASES BACKGROUND (cont1nued) criteria, for the survei 11 ances of concentr,ati on, fl ow rate and boron enri chmerrt is > 1. 69, which rafl ects th.at the SLC System exceeds the criter1a of Reference 1.
The SLC System consists of a boron solutio.r'I storage tank, two positfve displacement pumps, two explosive valves that are provided in parallel for redundancy, and associated piping and valves used to transfer b*o'rated water from the storage tank to the reactor pressure vessel C.RPV). The borated solution is discharged near the bottom of the1 core shroud, wh~re it then mixes wfth the cooling water rising t'hrough the core. A smaller tank containing demineralized water is provided for testing purposes.
APPLICABLE      The SLC System is manually initiated from 1he main control SAFETY ANALYSES room, as directed by the emergency operating procedures, if the operator believes the reactor canno_t be shut down, or kept shut down, with the control rods. The SLC System is used iA the event that enough control rods cannot be inserted to accomplish shutdown and cooldown in the norma1 manner. The SLC System injects borated water into the reactor core to ad.ct negative reactivi,ty to compensate for all 0f the various reactivity effects that could occur during plant operations. To meet this objective, it is necessar'y to inject a quantity of boron, which produces *a concentration of 66Q ppm of natural boron, in the reactor coolant at 68&deg;F. To allow for potential lea,k.age and imperfect mixing in the reactor system, an additional amount of boron equal to 25% of the amount cited above is added as a minimum (Ref. 2). The minimum level of sodium pentaborate in solution in the SLC tank (i.e., SR 3.1,7.1, ~ 52%) and the temperature versus concentration limits in Figure 3.1.7-1 are calcu1ated such that the required concentration is achieved~ with addition~l margin associated with using highly enriched boron to increase the rate of Boron-10 inj.ection, accounting for dilution in the ,RPV with normal water 1evel arid incl ud'i ng the water vol urne in the residual heat r~moval shutdown cooltng piping and in the recircLllation loop piping. This quantity of borated solution is the amount that is above the pump suction shutoff level in the boron solution storage tank. No credit 1s taken for the portion of the tank volume that cannot be injected. The maximum allowable concentration of_ sodium pentaborate depicted in figure 3.1.7-1 has been established to ensure that the solution saturation temperature does not exceed 43"'F. Using highly enriched boron (i.e., SR 3 .1. 7 .10, ~ 92,. 0%) in the SLC System increases the ra.te of (continued)
PBAPS UNIT 2                          B 3.1-40                    Revision No. 114
 
SLC System B *3 .1. 7
* BASES APPLICABLE SAFETY ANALYSES Boron-10 injection and functions to shutdown the reactor core faster. This limits the heat generated that is (continued)    transferred to the suppression pool during an ATWS event.
L1miting the heat transferred to the suppression pool rna1ntains the pool below desig.n limits, wh~ch ensur-es adequate NPSH is available for the ECCS pumps without credit for wntainment accident pressure.
The sodium pentab~rate solution in the SLC System is also used, post-LOCA; to rrraintain suppression pool pH at or above
: 7. The system parameters used in the calculation are the minimum allowable volume, Boron-10 enrichment, and concentration Of sodium pentaborate in solution in the SLC tank. These minimum allowable values are required to maintain suppression pool pH~ 7.0 post-L0CA. This prevents radioactive iodine from re-evolving, which limits the iad1ne release to the plant environs and minimizes the radiological consequences to comply with 10 CFR 50.67 limits (Ref. 3).
The SLC System satisfies Criteria 3 and 4 of the NRC P-olicy Stateme.nt .
* LCQ              The OPERABILITY of the SLC System ~rovides backup capability for reactivity control independent of normal reactivity control provisions provided by the control rods. The OPERABILITY of the SLC System is based on the conditions of the borated solution in the storage tank and the availability of a flow path to the RPV, including the OPERABILITY of the pumps and valves. Two SLG subsystems are required to be OPERABLE; each contains an OPERABLE pump, an explosive v.alve, and associated piping, valve.s, and instrumeflts and controls to ensure an OPERABLE flow ~ath.
  *APPLI CAB IL !TY  In MODES 1 and 2, shutdown capability is required. In MODES 1, 2, and 3,. SLC System injection capability is required in order to maintijin post OBA L0CA suppression pool pH. In MOD.ES 3 a/rid 4, control rods qre not able to be withdrawn since the re.actor mode switch is in shutdown an:d a control rod block is applied. This prov1des adequate controls to ensure that the reactor remains subcritical. In MODE 5, only a single control rod can be withdrawn from a core cell containing fue1 assemblies. Demonstration of adequat_e SDM (LCO 3.1.1, "SHUTDOWN MARGIN (SOM)") ensures that the reactor will not become critical. Therefore, the SLC System is. not required to be OPERABLE when only a single control
* PBAPS UNIT 2 rod can be w~thdrawn .
B 3.1-41 (continued)
Revision No. 114
 
SLC System
                                                                          .B 2 .. 1. 7
* BASES APPLICABILITY (continued)
In MODES 1, 2, and 3, the SLC System must be OPERABLE to ensure that offsite doses remain within 10 CFR 50.67 (Ref. 3) limits following a LOCA involving signif,cant fission product releases. The SLC System is designed to maintain suppression poo1 pH, at or above 7 following a l0CA involving significant fission product releases to ensure that iodine will be retained in the suppression pool water.
ACTIONS      A.1 and A. 2 If the boron solution concentration is> 9.82% weight but the concentration and temperature of boron in solution and pump suction piping temperature are within the limits of Figure 3.1.7~1, operat1on is permitted for a limited period since the SLC subsystems are tapable of performing the i nt,ended functi o*n. It is not r,.ecessa ry under these conditions to declare both SLC subsystems inoperable since the SLC subsystems are capable of performtng their intended function ..
The concentration and temperature of boron in solution and pump suction piping temperature must be verified to be within the limits of Figure 3,1.7-1 within 8 hours and once per 12 hours thereafter (Required Action A.1). The temperature ve_rsus concentration curve of Figure 3.1.7-1, for concentrations> 9.82% weight, ensures a l0&deg;F margin will be maintained above the saturation temperature. This ver-ifi cation ensures that boron does not precipitate out of solution in the storage tank or in the pump suction piping due to low boron solution temperatu~e (below the saturation temperature for the given concentration). The Completion Time for performing Required Action A.1 is considered acceptable given the low probability of a Design Basis Accident (OBA) or transient occurring concurrent with the failure of the control rods to shut down the reactor and operating experience which has shown there are relatively slow variations in the measured parameters of concentration and temperature over these time periods.
Continued operation is only permitted for 72 hours before boron solution concentration must be restored to~ 9.821 weight. Taking into*consideration that the SLC System design capability still exists for vessel injection under these conditions and the low probability of the temperature and concentration limits of Figure 3.1.7-1 not beirig met,. the allowed Completion Time of 72 hours is acceptable and provides adequate time to restore concentration to within limits.
(continued)
PBAPS UNIT 2                      B 3.1-42                      Revision No. 114
 
SLC System B 3. L 7 BASES ACTIONS      .lL.1 (continued)
If one SLC subsystem is inoperable for reasons other than Condition A*, the inoperable subsystem mu.st be restored to OPERABLE status within 7 days. In this conditi,on, the remaicting OPERABLE subsystem is adequate to perform the shutdown function. How~ver, the overall reliability is reduced because a .s~ngle failure fn the remaining OPERABLE subsystem coul~ result in the loss of SLC System shutdown capabiltty. The 7 day Completion Time is based on the avai 1ability of an OPERABLE subsystem capable df performi hg the intended SLC System function and the low probability of a DBA or severe transient occurring concurrent with the failure of the Control Rod Drive (CRD) System to shut down the plant .
                .c......1 If both &LC subsystems are inoperable for reasons other than Condition A. at least one subsystem must be restored to OPERABLE stat1:Js within 8 hours. The allowed Completion Time of 8 hours is cGnsidered acceptable given the Jow probability of a OBA or transient occurring concurrent with the failure of the control rods to shut down* the reactor.
D.l and 0.2 If any Required Action and asseciated Completion Time is not met, the plant must be trought to a MO-DE in which the LCO d oes nat ffp p1y . To a ch i e ve t hi s s t at u.s , th e p1a nt rn us t be brought to MODE 3 within 12 hours and MODE 4 within 36 hours.
The allowed Completion Tirnes are reasonable, based on operating experience, to reach the required MODES from full poweer conditions in an orderly .manner and without challenging plant systems.
{continued)
* PBAPS UN IT 2                      B 3.1-43                                ReV1.sion No*. 114
 
SLC System B 3.1.7
* BASES  (continued)
SURVEILLANCE REQUIREMENTS SR 3.1.7.1. SR 3.1.7.2. and SR 3.1.7,3 SR 3.1.7.1 through SR 3.1.7 .. 3 verify certain characte,ri.stits of the SLC System (e.g., the level and temperature of the borated solution in the storage tank), thereby ensuring SLC System OPERABILITY without disturbing normal plant operation. These Surveillances ensure that the proper borated solution level and temperature, including the temperature of the pump suction piping, are maintained.
Maintaining a minimum specified borated solution temperature is important in ensuring that the boron remains in solution and does not precipitate out in the storage tank or in the pump suction piping. The temperature limit specified in SR 3.1.7.2 and SR 3.1.7.3 and the maximum sodium pentaborate concentration specified in Figure 3.1.7-1 ensures that a 1O&deg;F margin will be maintained above the saturation temperature. Control room alarms for low SLC storage tank temperature and low SLC System piping temperature a re available and are set at 55&deg;F. As such, SR 3.l.7.2 and SR 3.1.7.3 may be satisfied by verifying the absence of low temperature alarms for the SLC storage tank and SLC System piping. The Surveillance Frequency fs controlled under the Surveillance Frequency Control Program.
SR 3.1.7.4 and SR 3.1.7.6 SR 3.1.7.4 verifies the continuity of the explosive charges in the injection valves to ensure that proper oper~tion wtll occur if required. Other administrative controls. such as those that limit the shelf life of the explosive charges, must be followed. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR 3 .1. 7. 6 verifies that each valve in the system is in its correct position, but does not apply to the squib (i.e.,
explosive) valves. Verifying the correct alignment for manual and power operated valves in the SLC System f1ow path provides assurance that the proper flow paths will exist for system operation. A valve i~ also allowed to be in the nonaccident position provided it can be aligned to the accident position from the -control room, or locally by a dedicated operator at the valve control. This is acceptable since the SLC System is a manually initiated system. This Surveillance also does not apply to valves that are lock.ed, sealed, or otherwise secured in position since they are verified to be in the correct position prior to locking,
* PBAPS UNIT 2 sealing, or securing. This verification of valve alignment B 3.1-44                    Revision No. 114
 
SLC System B 3.1.7
* BASES SURVEILLANCE REQUIREMENTS sR  3
* 1. Z*4 and  sR  3
* 1. Z* 6  ( co,n ti nu e d )
does not require any testing or valve manipulation: rather, it involves veriffcation that those valves capable of betng mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR    3.1.7.5 This Surveillance requires an examination of the sodium pentaborate s:olution by using .chemical analysis to ensure that the proper corn::entration of boron exists in the storage tank. Havfng the proper concentratfon of boron in the storage tank ensures the SLC subsystems wil1 perform their intended function of injecting no less than the minimum quantity of Borori-10 and amount of sodium pentaborate required by ATWS analyses. The SLC subsystems function to quickly shutdown the reactor in the event of an ATWS. This limits the heat generated that is trqnsferred to th,e suppression poo.l during an ATWS event. LimHing the heat transferred to the suppression pool maintains the pool below desi,gn limits. which ensures adequate NPSH is avai1able for the ECCS pumps without credit for containment accident pressure. The SLC subsystems also function to maintain suppression pool pH~ 7.0 under post-LOCA conditions.
SR 3.1.7.5 must be performed anytime boron or water is added to the storage tank solution to determine that the boron solution concentration is 2: 8.32.%' weight and$ 9.82% weight.
SR 3.1.7.5 must also be p*erformed anytime the te.mperature is res t o red t o wit hi n l i mit s t o en s ure th a t no .s i gnif i ca nt boron precipitation occurred. The Surve1llance Frequency is controlled under the Surveillance Frequency Control Program.
SR 3.1.7.z Deleted SR    3,1.7,8 Demonstrating that each SLC System pump develops a flow rate~ 49 . .1 gpm at a discharge pressure c:: 1275.psig ensures that pump performance ~as not degraded below destgn values during t~e fuel cycle. This minimum pump flow rate requirement ensures that, when combined with the sodium
* P'BAP'S UN IT 2 pentaborate B 3.1-45 (continued)
Revision No. 114
 
SLC System B 3.1.7
* BASES SURVEILLANCE REQUIREMENTS SR 3,1.7.8 (continued) solution ~oncentration requirements, the rate of negative reactivity insertion from the SLC System will adeciuately compensate for the positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. The rate of negative reactivity insertion is          ,
increased by using highly enriched boron in the SlC System so1ution that increases the rate of Boron-10 inje~tion ahd functions to shutdown the reactor core faster*. This Hmits the heat generated that is transferred to the suppressio~
pool during ar:t ATWS event. Limiting the heat traflsferred to the suppression pool maintair:1s the PQOl below design limits, which ensures adequate NPSH is available for the ECCS pumps without credit for containment accident pressure. This test confirms one point on the pump design curve and is i ridi cative of overall performance. Such inservi ce inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this Surveillance is in accorda.Rce with the INSERVICE TESTING-PROGRAM .
* SR 3.1.7 .9 This Surveillance ensures that there is* a functioning flow path from the boron solution storage tank to the RPV, including, the firing of an explosive valve. The. replacement charge for the explosive valve shall be from th~ same manufactured batch as the one fired or from anothe,r batch that has been certified by having one of that. batch successfully fired. The Surveillance may be performed in separate steps to prevent i,:ijecting boron into the RPV. An acceptable method for verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
(continued)
* PBAPS UNIT 2                    B 3.1-46                  Revision No. 140
 
SLC System B 3.1.7 BASES SURVEILLANCE  .SR  3,.1.7.10 REQUIREMENTS (continued) *Enriched sodium pentaborate solution is made by mixing granular, enriched so*di um pentaborate with water. Isotopic tests on the granular sodium pentaborate to verify the actua1 B-10 enrichment must be performed prior to addition
                *to the SLC tank in order to ensur~ that the proper B-10 atom percent.age is being used, The tests may use vendor certification ~ocuments.
REFERENCES      1. 10 CFR 50 . 6 2 .
: 2. UFSAR, Se.ct1on 3.8.4.
: 3. 10 CFR &0.67,
* PBAPS UNIT 2                        B 3.1-47                Revision No. 130
 
SDV Vent and Drain Valves B 3.1.8
* B 3 .. 1 REACTIVITY CONTROL SYSTEMS B 3 .. 1. 8 Scram D1 scharge Volume (SDV) Vent and Dra1 n Valves BASES BACKGROUND            The SDV vent and drain valves are normally open and discharge any accumulated water in the SDV to ensure that suffic1ent volume is ava11able at all t1mes to allow a complete scram. During a scram, the SDV vent and drain valves close to conta1n reactor water. As discussed 1n Reference 1, the SDV vent and dra1n valves need not be cons1dered primary conta1nment isolation valves (PCIVs) for the Scram Discharge System. (However, at PBAPS, these valves are cons1dered PClVs.) The SDV 1s a volume of header piping that connects to each hydraul1c control unit (HCU) and drains into an 1nstrument volume. There are two SDVs (headers) and a common instrument volume that receives al1 of the control rod drive (CRD) discharges. The instrum*ent v.ol ume is connected to a common drai Ii 1 i ne w1 th two valves in series. Each header is connected to a common vent line with two valves in ser1 es for a total of four vent valves.
The header pip1ng is sized to rece1ve and conta1n all the
* APPLICABLE SAFETY ANALYSES water discharged by the CRDs during a scram. The design and functions of the SDV are described in Reference 2.
The Design Basis Accident and transient analyses assume all of the control rods are capable of scramming. The acceptance cr1terta for the SDV vent and drain valves are that they operate autom~ti call y to c-1 ose during scram to lim1t the amount of reactor coolant d1scharged so that
                        -adequate core cooling is maintained and offsfte do~es remain within the 11mits of 10 CFR 50.67 (Ref. 3).
Isolation of the SDV can also be accomplished by manual closure of the SDV valves. Additionally, the discharge of reactor coolant to the SDV can be term1nated by scram reset or closure of the HCU manual isolation valves. For a bound1ng leakage case, the offsite doses are well within the limits of 10 CFR 50.67 (Ref. 3), and adequate core cooling is maintained (Ref. 1). The SDV vent and drain valves allow continuous drainage of the SDV during normal plant operation to ensure that the SDV has sufficient capacity to contain the reactor coolant discharge during a full core scram. To automatically ensure this capacity, a reactor scram (LCO 3.3.1.1, "Reactor Protection System (RPS)
InstrumentationR) is initiated if the SDV water level in the
* PBAPS UNIT 2                              B 3.1-48 (continued).
Revision No. 75
 
SDV Vent and Drain Valves B: 3 .1.8
* BASES APPLICABLE SAFETY ANALYSES (continued) instrument volume. exceeds a specified setpoint. The setpoint is chosen so that all control rods are inserted before the SDV has insufficient volume to accept a full scram.
SDV vent and drain valves satisfy Criterion 3 of the NRC Policy Statement.
LCD            The OPERABILITY of all SDV vent and drain valves ensures that the SDV vent and drain valves will close during a scram to contain reactor water discharged to the SDV piping.
Since the vent and drain lines are provided with two valves in series, the single failure of one valve in the open position will not impair the isolation function of the system. Additionally, the valves are required to be opened following scram reset to ensure that a path is available for the SDV piping to drain freely at other times.
APPLICABILITY    In MODES 1 and 2, scram may be required; therefore, the SDV ve.nt and drain valves must be OPERABLE. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate controls to ensure that only a single co~trol rod can be withdrawn. Also, during MODE 5, only a single control rod can be withdrawn from a core cel1 containing fuel assemblies. Therefore, the SDV vent and drain valves are not required to be OPERABLE in these MODES since the reactor is subcritical and only one rod may be withdrawn and subject to scram.
ACTIONS          The ACTIONS Table is modified by Notes indicating that a separate Condition entry is allowed for each SDV vent and drain line. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable SDV line. Complying with the Re qui red Actions may allow for continued operation, and subsequent inoperable SDV lines are governed by subsequent Condition entry and application of associated Required Actions.
When a line is isolated, the potentia1 for an inadvertent scram due to high SDV level is increased. During these periods, the line may be unisolated under administrative control. This allows any accumulated water in the line to be drained, to preclude a reactor scram on SDV high level.
This is acceptable since the administrative controls ensure the valve can be closed quickly, by a dedicated operatorj if a scram occurs with the valve*open .
* PBAPS UNIT 2                        B. 3 .1-49                  Revision No. 57
 
SDV Vent and Drain Valves B 3.1.8
* BASES ACTIONS (continued)
Ll When one SDV vent or drain valve is inoperable in one or more lines, the associated line must be isolated to contain the reactor coolant during a scram. The 7 day Completion Time is reasonable, given th,e level of redundancy 1n the lines and the low probability of a scram occurring during the time the valves are inoperable and the line is not isolated. The SDV ii still iso1able since the redundant valve in the affected line is OPERABLE. During these periods, the single failure criterion may not be preserved, and a higher risk exists to allow reactor water out of the primary system during a scram.
Ll If both valves in a line are inoperable, the line must be isolated to contain the reactor coolant during a scram .
The 8 hour Completion Time to isolate the line is based on the low probability of a scram occurring while the line is not isolated and unlikelihood of significant CRD seal leakage.
Ll If any Required Act1or;i and associated Completion Time is not met, the plant must be brought to a MOOE in whic'h the LCD does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Time of 12 hours is reasonable~ based on
                *operating experience, to reach MODE 3 from fuJl power conditions in an orderly manner and without challenging plant systems.
( continued)
* PBAPS UN IT 2                    B 3 .1-50                      Revision No. 57
 
SDV Vent and Drain Valves B 3.1.8
* BASES  (continued)
SURVEILLANCE REQUIREMENTS SR  3,1.8,1 During normal operation, the SDV vent and drain valves should be in the open posttion (except when performing SR 3.1.8,2 or SR 3.3.1.1.9 for Function 13, Manual Scram, of Table 3.3.1.1-1) to allow for drainage of the SDV piping.
Verifying that each valve is in the open position ensures that the SDV vent and drain valves will perform their intended functions during normal operation. This SR does not require any testing or valve manipulation; rather, it involves verffication that the valves are in the correct position. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR  .3.1.8,2 During a Scram. the SDV vent and drain valves should close to contain the reactor water discharged to the SDV piping.
Cycling each valve through its complete range of motion (closed and open) ensures that the valve will function properly during a scram. The Surveillance Frequency is
* controlled under the Survei 11 ance Frequency Control Program.
SR 3.1.8.3 is an integrated test of the SDV vent and drain valves to verify total system performance. After receipt of a simulated or actual scram signal, the closure of the SDV vent and drain valves is verified. The closure time of 15 seconds after receipt of a scram signal is !}ased on the bounding leakage case evaluated in th accident analysis (Ref. 2). The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1 and the scram time testing of control rods in LCO 3.l.3 overlap this Survei 11 ance to provide complete testing of the assumed safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
(continued)
* PBAPS UN'lT 2                        B 3.1-51                      Revision No. 86
 
SDV Vent and Drain Valves B 3.1.8
* BASES  (continued)
REFERENCES        l. NUREG-0803, "Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping,"
August 1981.
: 2. UFSAR, Sections 3.4.5.3.1 and 7.2.3.6.
: 3. 10 CFR 50.67 .
* PBAPS UNIT 2                      B 3.1-52                    Revision No. 86
 
APLHGR 8 3.2.1
* B 3.2  POWER DISTRIBUTION LIMITS B 3.2.1  AVERAGE PLANAR UNEAR Hf:AT G'ENERArION RATE (APLHGR)
BASES BACKGROUND        The APLHGR is a measu,re of the average LHGR of all the fuel rods in a fuel assembly at any axi.al location. Limits on the APLHGR are specified to ~nsure that the peak cladding temperature (PCT) during the postulated design basis loss of
                      .cool ant accident ( LOCA) does not exceed the Hmits specified in 10 CFR 50.46.
APPLICABLE        The analytic;al methods and assumptions used in evaluating SAFETY ANALYSES    Design Basis Accidents (DBAs) that determine the APLHGR limits are presented in References 1, 2, 3, 4, 5, and 7 .
* PBAPS UNIT 2                          B 3.2-1                    Revision No. 49
 
APLHGR B 3.2.1
* BASES APPLICABLE.
SAFETY ANALYSES (continued)
L0CA analyses ,a re performed to ensure that the *APLHGR limits are adequate to meet the PCT and maximum oxidation limits of 10 CFR 50.46. The analysis is performed using calculational models that are consistent with the requirements of 10 CFR 50, Appendix K. A _complete discussion of the analysis code is provided in Reference 11. The PCT following a postulated L0CA is a function of the average heat genetati0n rate of all the rods of a fuel assembly at any axial location and is not strongly influenced by the rod to rod power distribution within an assembly. A conservative mult1plier is applied to the LHGR assumed in the L0CA analysis to account for the uncertainty associated with the measurement of the APLHGR.
For single recirculation loop operation, a conservative multiplier is applied to the APLHGR as specified ih the COLR (Ref. 12), This is due to the conservative analysis assumption of an earlier departure from nucleate boiling with one recirculation loop available 1 resulting in a more severe cladding~heatup during a ~0CA.-
Powet-dependent and flow-dependent APLHGR adjustment factors may also be provided per Reference 1 to ensure that fue.l design limits are nbt exceeded due to the occurrence of a postulated transient event during operation at off-rated*
(less than 100%) reactor power or core flow conditions.
These adjustment factors are applied, if required, per the C0LR and decrease the allowable APLHGR value.
The /4PLHGR satisfies Criterion 2 of the NRC Policy Statement.
LCD              The APLHGR limits specified in the C0LR are the result of the fuel design and OBA ~halyses. The limits are developed a s a fun ct i on ,o f exp os ure a nd a re a pp l i ed pe r th e CO LR .
C
* PBAPS UN IT 2                          B 3.2-2                              Revision No. 49
 
APLHGR B 3.2.l BASES LCO
( con,ti nued) With only one rectrculatiOh loop in operation, in conformance with the requirements of LCQ 3.4.1, "Recircul,ation Loops Operating," the limit is determ-ined by multiplying the exposure dependent APLHGR limit by a.
conservator factor.
APPLICABILITY    The APlHGR limits a.re primarily derived from LOCA a.naJyses that are assumed to occu,r at high powe,r levels. Design calculations (Ref. 6) and operating experience have shown "that as power is reduced, the margin to the required APLHGR limits increases. This 1;rend continues down to the power range. of 5% to 15% RTP when: entry into MODE 2 occurs. When in MODE 2. the wide range ne1:1tror:i monitor period-short .scram function provides prompt scram initiation during any significant transient, thereby effectively ,removing any APLHGR limit compliance concern in MODE 2. Therefore, at THERMAL POWER levels< 22,6% RTP, the reactor is operating with substantial margin to the APLHGR limits; thus, this LCO is not required .
* ACTIONS    I      A...1 If any APLHGR exceeds the required limits. a:n -assumption regarding an initial condition of the DBA analyses may not be met. Therefore, prompt action should be taken to 're~tore the APL.:HGR(s) to within the required limits such that the plant operates withih analyzed conditions and within design limits of the fuel rods. The. 2 hour Completion, Time is sufficient to restore the APLHGR(s) to within its limits and is acceptable based on the low probability*of a DBA occu~ring simultaneously with the APLHGR out of specification.
Jhl If the APLHGR cannot be restored to within its required limits within t.he associated Completion Time,, the plaht must be brought to a MOqE or other specified condition in which the LCO does not apply.. To achieve this status, THERMAL POWER mast be. reduc~d to < 22.6% R1P within 4 hours. The (continued)
* PBAPS UNIT 2                        B 3.2-3                      Revision No. 143
 
APLHGR B 3.2.1
* BASES ACHONS      .B..J. (continued) allowed Completion nme 1s reasonable, based on operating experience, to reduce THERMAL POWER to < 22. 6% RTP in an or<lerl y manher and without ch all engi ng pl ant systems.
SURVEILLANCE  SR 3,2.1.,l REQUIREMENTS APLHGRs a re required to be 1nit i ally calculated wHhi n 12 hours after THERMAL POWER 1s ~ 22.6% RTP and then periodically thereafter. They are compared to the specified limits in the COLR to ensure that the reactor is opera ti n,g within the assumptions of the safety analysis. The 12 hour a 11 owance after THERMAL POWER ~ 22. 6% RTP ,is achf eved is acceptable given the large inherent margin to operating limits at low power levels. The Surveill~rrce Frequency is controlled under the Surveillance Frequency Control Program.
REFERENCES    1. NED0-24011-P-A, "General ilectric Standard Application for Reactor Fuel," latest approved revision .
* 2.
3.
4.
UFSAR, Chapter 3.
UFSAR, Chapter 6.
UFSAR, Chapter 14.
: 5. NED0-24229-1, "Peach Bottom Atomic Power Statton Units 2 and 3, Single Loop Operation," May 1980.
: 6. NEDC-32.162P, "Maximum Extended Load Line Limit and ARTS Improvement Program Analyses for Peach Bottom Atomic Power Station Units 2 and 3," Revision 2j March 1995.
: 7. NEDC-33566P, "Safety Analysis Report for Exelon ~each Bottom Atomic Power Station, Vrrits 2 and 3, Constant Pressure Power Uprate," Revision 0.
: 8. Deleted
: 9. NED0-.30130-A, "Steady State Nuclear Methods,"
April 1985.
                                                                        <conti 011ed >
* PBAPS UNIT 2                      8 3.2-4                      Revision No. 143
 
APLHG~
B. 3.2.1
* BASES REFERENCES (continued)
: 10. Deleted
: 11. NEDC-32163P, "Peach Bottom .Atomic Power Station Units 2 and 3 SAFER/GESTR-LOCA Loss-of-Coolant Accident
                    *Analysis," January 1993.
: 12. Peach Bottom Unit 2 Co.re Operating Limits Report (COLR)_.
: 13. NEDC-33873P, "Safety Analysis Report for Peach Bottom
                    .Atomic Power Station, U'r:1its 2 and 3, Thermal Power Optimization," Revision 0 *
* PBAPS UNIT 2                    B 3.2-5                      Revision  No. 143
 
M(PR B 3.2.2
* B 3.2 B 3.2.2 POWER DISTRIBUT,ION LIMTTS MlNIMUM CRITICAL POWER RATID (MCPR)
BASES BACkGROUND          MCPR is a ratio of the fuel ass~mbly power that would resul~
in the onset of boiltng transition to the actual fuel as.sernblY power. The operating limit MCPR is established to ensure that no fuel damage results during_ abnQrmal operational transi-ents, and that 99. 9% of the fuel ro_ds are not susceptible to boiling transition if the limit is not violated. A1tnough fuel damage does not necessarily occur if a fuel rod actually experienced boiling transiti5n (Ref. 1), the critical power at which boiling transition.is calculated to occur has been adopted as a .fuel design criterion.
The onset of transition boiling is a phenomenon that is readily detected during the testing of var}ous fuel bundle designs. Based on these experimental data, correlations have been developed to predict critical bundle power (i.e.,
the bundle power level at the onset of transition boiling) for a given set of plant parameters (e.g., reactor vessel pres.sure, flow, and subcooling). Becaus~ plant operating concj1tions and bundle power levels are mon1t:ored and determined relatively easily, morritoring the MCPR is a convenient way of ensuring that fuel failures due to inadequate cooling do not occur.
APPLICABLE        The analytic.al methods and a.s-sumptions used tn evaluating SAFETY ANALYSES    the a.bnorrnal op.erati onal transients to establish the operatir,g limit MCPR are presented in References 2, 3, 4, 5, 6, 7, 8, and 9. To ensure that the MC~R Safety Limit (SL) ts not exceeded durh1g any transient event that occurs with moderate frequency, limiting transients have been analyzed to determine th.e largest reduction in critical power ratio (CPR) .. The types of transients evaluated are l0ss of flow, increase in pressure and po.wer, positive reactivity insertion, and coolant temperat~re decrease. The limiting transient yields the largest change in CPR (.1CPR). Wben the largest .1CPR (corrected for ari,alytical uncertainties) is combined with the MCPR99. 9i, the requi. red operating limit .MCPR i.s obtained .
* PBAPS UNIT 2                          B 3.2-6                      Revision No. 157
 
MCPR B ~.2.2
* BASES APPLICABLE
  -SAFETY- ANALYSES (continued)
MCPR99.91 is determined to ens*ure more than 99. 9% of the fuel rods in the ~ore are not susceptibie tQ boiling transition usiTig a statistical model that combines al1 the uncertainties in operating parameters and the procedures used to C?lculate critf*cal power. The proba.bility of the occurrenca of boiling ttansition is determined using the approved Critical Power correlations. Details of the MCPRgg.91 calculation are given in Reference. 2. Reference. 2 also inc1udes a tabulation of the uncertainties and the nominal values of the p.arameters used in the MCPR99.9t s-tatisti,cal analysis, The MCPR operating limits c;1 re derived from the MCPR99.9t value and transient analysis, and are*dependent on the operating core flow and power state (MCPRt and MCPRp, respectively) to ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency (Refs. 6, 7, 8, and 9). flow dependent MCPR limits are d~term,ned by steady state thermal hydraulic methods wtth key phys~cs response inputs benchmarked using the three dimensional BWR simulator code (Ref. 10) to analyze slow flow runout tra.nsients. Tile flow dependent operating limit, MCPRt,, is
                    ~valuated based on a single recirculation pump flow runout event (Ref. 9).
Power dependen! MCPR limi~s CMCPRP) are determined by
                    ~pproved transient analysis models (Reference 2). Due to the sensitivity of the transient response to initial core flow levels at power 'levels below those at which the turbine stop va1ve closure and turbine. control valve fast clo.sure scrams are bypassed, high and low flow MCPRP operating limits are provided for operating between 22.6% RTP and the previously mentioned bypass power level.
The MCPR satisfies Criterion 2 of the NRC Policy $ta,tement.
LCD              The MCPR operatin,g 7imits s_pecified tn the COlR CMCPR99.9%
value, MCPRt values, and MCP.Rp vilues} are the result of the Design Basis Accident (OBA) and transient analysis. The operating limit MCPR is determined by the larger of the MCPRf and MCPRP limits, which are based on the MCPRgg_gz limit
                    ~pecified in the COLR.
APPLICAB'I UTY    The MCPR operating limits are pririiarily der-ived from hansi ent analyse-s that are assume.ct to occur at high power 1eve1s. Below 22.6% RTP, the react6r is operating at a mini mum reci rculat.i o_n pump speed and the moderator void r'clt i o is sma 11. Survei 11 ance o.f thermal limits below 22.6% RTP is unnecessary due to the large inherent margin that ensures-that the MCPR SL is not exceeded even if a limiting t~ansient o~curs. Statfstical analyses indicate that the nominal value of the initial MCPR expected at 22 . 6% RT P i s > 3 . 5 . Stud i e*s of th e ya r i ati on of l i mi t i ng transient behavior have peen performed over the range of power and
* PBAP-S UN-IT 2                          B 3.2-7                            Revision No. 1.57
 
MCPR 8 3 .2.2
* BASES APPLICABILITY (continued) flow conditions. These studies encompass the range of key actual plant parameter values important to typically limiting transients. The results of the~e studies demorrstrate that a margin is expected between pe.rformance and the MCPR requirements, and that margins increase as power is reduced to 22.6% RTP. Tl:lis trend is expected to continue to the 5% to 15% power range when entry into MODE 2 occurs. When in MODE 2. the wide range neutron monitor period-short function provides rapid scram initi.ation for any significant power increase transient, which effectively eliminates any MCPR compliance concern. Therefore, at THERMAL POWER 1 evel s < 22. 6% RTP, the reactor is operating with substantial margin to the MCPR limits and this LCO is not required.
ACTIONS      A.,_.1 If any MCPR is outside the required limits, an assumption regarding an initial condition of the design basis transient analyses may not be met. Therefo.re, prompt action should be taken to restore the MCPR(s) to within the required limits such that the plant remains operating within analyzed conditions. The 2 hour Completion Time is normally sufficient to restore the MCPR(s) to within its limits and is acceptable based on the low probab.ility of a transient or DBA occurring simultaneously with the MCPR out of specification .
                .Ll.
If the MCPR cannot be restored to within its required limits within the associated Completion Time, the plant. must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to< 22.6% RTP within 4 hours. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to< 22~6% RTP in an orderly manner and without challenging plant systems.
SURVEILLANCE  SR 3.2.2,1 REQUIREMENTS The MCPR is required to be initially calculated within 12 hours after THERMAL POWER is~ 22.6% RTP and periodically thereafter. It is compared to the specified limits
* PBAPS UNIT 2                    B 3.2-8 (continued)
Revision No. 143
 
MCPR 8 3.2.2
* . BASES SURVEILLANCE R_EQUIREMENTS in the COLR (Ref. 12) to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour allowance after THERMAL POWER~ 22.6% RTP is achieved is acceptable given the, large inherent margin to operating limits at low power levels. The Survei-llance Frequency is controlled under the Surveillance Frequency Control Program.
SR 3-.2.2.2 Because the transient analysis takes credit for conservatism in the scram speed performance, it must be demonstrated that the specific scram speed distribution is consistent with that used in the transient. analysis. SR 3.2.2.2 deter-mines the value of -r, which is a measure of the actual scram speed distribution compared with the assumed distribution. The MCPR operating limit is then determined based on an interpolation between the appli~able limits for Option A (scram- times of t.CO 3.1.4, "Control Rod Scram Times") and Option B (realistic scram times) analyses. The parameter -r must be determined once within 72 hours after each set of scram time tests required by SR 3.1.4.1, SR 3*_1.4.2, and SR 3.1.4.4 because the effective scram speed distribution may change during the cycle or after maintenance that could affect scram times. The 72 hour Completion Time is acceptable due to the relatively minor changes int expected during the fuel cycle.
* REFERENCES    1. NUREG-0562, June 1979.
: 2. NE00-24011-P-A, "General Electric Standard Application for Reactor Fuel," latest approved revision.
3.. UFSAR, Chapter 3.
: 4. UFSAR, Chapter 6.
: 5. UFSAR, Chapter 14.
: 6. NED0-24229-1, "Peach Bottom Atomic Power Station Units 2 arid 3, Single Loop Operation," May 1980.
Ccontiniaed)
* PBAPS tJNIT 2                    B 3.2-9                    Revision No. 143
 
MCPR B 3.2.2
* BASES REF=ERENCES (continued)
: 7. NEDC-32162P, "Maximum Extended Load Line Limit and ARTS Improvement Program Analyses for Peach Bottom Atomic Power Station Units 2 and 3," Revision 2, March 1995.
: 8. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomii:'Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision Q.
: 9. NEDC-32428P, ''Peach Bottom Atomic Power Station Unit 2 Cycle ll ARTS Thermal Limits Analyses," December 1994.
: 10. NED0-30130-A, "Steady State Nuclear Methods,''
April 1985.
: 11. NED0-24154, "Qualification of the One-Dimensional Core Transient Model for .Boiling Water Reactors,"
October 1978. *
: 12. Peach Bottom Unit 2 Core Operating limits Report (COLR).                    .
* 13 . NEDC-33873P, "Safety Analysis Report for Peach Bottom, Atomic Power Station, Units 2 and 3, Thermal Power Optimization," Revision 0.
PBAPS UNIT 2                                              Revision No. 143
* LHGR B 3.2.3
* B B
3.2 3.2.3 POWER DISTRIBUTION LIMITS LINEAR HEAT GEf-tERATION RATE (LHG.R)
BASES BACKGROUND        The LHGR is a measur~ of the heat generation rate of a fuel rod in a fuel ass~mbly at any axial location. Limits on LHGR are specified to ensure that fuel design limits are not exceeded anywhere in the core during normal operation, including abnormal' operational trans1 ents. E'xceedi ng the LHGR limit could potentially result in fuel damage and subsequent reTease of radioactive materials. Fuel design 11mits are specified to ensure that fuel system damage, fuel rod failure, or inability to cool the fuel does not occur during the anticipated operating conditions identified in Reference 1.
APPLICABLE        The analytical methods and assumptions used in evaluating SAFETY ANALYSES    the fuel system design are presented in References 1, 2, 3, 4,, 5, 6, 7, 8, 11, and 12. The fuel assembly is designe,d to
* ensure (in conjunction with the core* nuclear and thermal hydr<iulic design, plant equipment, instrumentation, and pr'Otecti on system) that fuel damage wil 1 not result in th~
r,elease of radioactive materials in excess of the guidelines 0 f 10 CFR , Pa rt s 20 , 50 , a nd 10 O, a s a pp 1i C'a b1e .
mechanisms that could cause fuel damage during operationa1 The transients and that are considered in fuel evaluations are:
a..
* Rupture of the fuel rod cl adding caused by strain from the relative expansion of the U0 2 pellet; and
: b. Severe overheating of the fuel rod cladding caused by 1nadequate cooling.
A value o,f 1% plastic strain of the fuel cladding has been defined as the limit below which fuel damage caused by overstraining of the fuel cladding is not expected to occur
                      <RB'f. 9).
Fuel design evaluations have bee:n performed and demonstrate that the 1% fuel cladding plastic strain design limit is not exceeded during continuous operation with LHGRs up to the operating limit specified in the COLR. The a.nalysis also
* PBAPS UNIT :2                            B 3 . .2-11                          Rev i s i o,n No . 101
 
LHGR B 3.i:3
* BASES APPLICABLE SAFETY ANALYSES (continued) the operating limit to account for abnormal operational transients, plus an allowance for densification power includes a1lowances for short term transient operation above spiking, Power-dependeJ;1t ahd flow-dependent LHGR adjustment factors may also be provided per Reference 1 to ensure that fuel design limits are not exceeded due to the occurrence of a postulated trarrsient event during o,peration at off-rated (1 ess than 100%) reactor power or core flow c1Jnditions.
These adjustment factors are applied, if req1:.1ired, per the C0LR and decrease the allowable LHGR value.
Additionally, for single recirculation loop operatfon, an LHGR multiplier may be provided per Referehce .1. Thi.s multiplier is applied per the C0LR and decreases the allowable LHCR va1ue. This additional margin may be necessary during SLO to *account for the conservative analysis assumpti,on of an earlier departure from nucleate boi1ing with only one recircu1ation Toop available.
The LHGR satis.fies Criterion 2 of the NRC Policy Statement .
* LC0            The LHGR is a basic assumption in th~ fuel design analysis.
The fuel has been designed to operate at rated core power with sufficient design margin to the LHGR calculated to ca.use a 1% fu.el cladding plastic strain. The operatirig limit to accomplish thi:s objective is specified in the C:0LR.
APPL])CABILITY  The LHGR limits are derived from fuel design ana,lysis that is limiting at high power level conditions. At core thermal power 1 eve ls < 22. 6% RTP, *the reactor is operating with a substantial margin to the LHGR limits and, there.fore, the Specification is only required when the reactor is operating at~ 22.6% RTP.
ACTIONS        Ll If any LHGR exceeds its required limit, an assumption regarding an initial condition of the fuel design analysis is not met. Therefore, prompt acti o.n should be taken to restore the LHGR(s) 'to within its required l,1 mits s:uch that the plant is operating wi_thin analyzed conditions. The (continued)
* PBAPS UNIT 2                        B 3.2-12                    Revision No. 143
 
LHGR B 3.2.3
* BAS'ES ACTIONS      &.l (continued) 2 hour Completion Time is normally sufficient to restore the LHCR(s) to within its 7imits a11d is acceptaple based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LHGR out of speci"fication.
If the LHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not .apply. To achieve this status, THERMAL POWER is reduced to< 22.696 RTP within 4 hours. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER TO< 22.6% RTP in an orderly manner and Without challenging plant systems.
(continued)
* PBAPS UNIT 2                  B 3.2-12a                  Revision No, 143
 
LHGR B 3.2.3
* BASES  (continued)
SURVEILLANCE REQUIREMENTS SR  3,2.3,1 The LHGR is required to be initially calculated within 12 hours after THERMAL POWER is~ 22.6\t RTP and periodically thereafter. It is compared to the specified limits in the COLR (Ref. 10) to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour allowance after THERMAL POWER~ 22.6% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels. The Surveil1ance frequency js cO'ntrol 1ed under the Survei 11 a.nc Frequency Control Program ..
REFERENCE$        1. NED0-24011-P-A, "General Electric Standard Application for Reactor Fuel," latest approved revision.
: 2. UFSAR, Chapter 3.
: 3. UFSAR, Chapter 6.
: 4. Uf'"SAR, Chapter 14.
: 5. NED0-24229-1, "Peach Bottom Atomic Power Station Units 2 and 3, Single-Loop Operation," May 1980.
: 6. NEDC-32162P, "Maximum Extended Load Line Limit an~
ARTS Improvements Program Analyses for-Peach Bottom Atomic Power Station Units 2 and'3," Revision 2, March 1995.
: 7. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Stati0n, Units 2 and 3. Constant Pressure Pow.er Uprate," Revision O.
: 8. NEDC-32163P, "Peach Bottom Atomic Power Station Units 2 and 3 SAFER/GESTR-LOCA Loss-of-Coolant Atcident Analysis," January 1993.
: 9. NUREG-0800, Section 4.2, Subsection II.A.2(g),
Revision 2, July 1981.
: 10.      Peach Bottom Unit 2 Core Operating Limits Report (COLR).
11,    G-080-VC-400, ~Peach Bottom Atomic Power Station Units 2 & 3 GNF2 ECCS-LOCA Evaluation," GE Hitachi Nuc1ear Energy, 0000-0100-8531-Rl, March 2011.
: 12. G-080-VC-272, "Peach Bottom Atomic Power Station ECCS-
* PBAPS UNIT 2
                            ~OCA Evaluation for GE14," General Electric Company, GENE-Jll-03716-09-02P, July 2000.
B 3.2-13                    Revision No. 143
 
LHGR
                                                                        ,r, 3.2.3
* BASES  (Co'ntinued)
REFERENCES        13. NEDC-33873P, nsafety Analys1s Report for Peach Bottom Atomic Power Station, Units 2 and 3, Thermal Power Optimization," RSvision 0 .
* PBAPS UNIT  2                    B 3.2-13a                  Revision No. 143
 
RPS lnstrumentat1on B 3.3.1.1 8 3.3  INSTRUMENTATION B 3.3.1.1  Reactor Protection System (RPS) Instrumentation BASES BACKGROUND        The RPS 1nit1 ates a reactor scram when one or more monitored parameters exceed their spectfied 11mits, to preserve the integrity of the fuel cladding and the Reactor Coolant System (RCS) and mihimiz.e the energy that must be a_bsorbed following a loss of coolant accident (LOCA). This can be accomplished either automatically or manually.
The protection and mon1tor1ng f~nctions of the RPS have been designed to ensure safe operation of the reactor. Thls is achieved. by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RPS1 as well as LCOs on other reactor system parame-ters and equipment performance. The LSSS are defined 1n this Speciftcat1on as the Allowable Values, which, in tonjunct1on wHh the LCOs, establis~ the threshold for protective system action to prevent exceeding acceptable lim1ts, including
* Safety Limits (Sls) during Oestgn Basis Accidents (DBAs) .
The RPS, as shown in the UFSAR Section 7.2j (Ref. 1),
includes sensors, relays, bypass circuits, and switches that are necessary to cause in1tiat1on 0f a reactor scram.
functional divers1ty is provided .by monitoring a w1de range of dependent and independent parameters. The input parameters to the scram logic are from instrumentation that monitors reactor vessel water level, reactor vessel pressure, neutron flux, main steam line isolation valve position, turbine control valve (TCV) fast closure trip 011 pressure, turbine stop valve (TSV) position, ctrywell pressure, scram discharge volume (SDV) water level, condenser vacuum, as well as reactor mode switch 1n shutdown position, manual scram signals, ~nd RPS test switches.
T~ere are at least four redundant sensor input signals from each of these parameters (with the exception of the manual scram s1gnal and the reactor mode sw1tclil in shut'Clown scram sfgnal). Most channels 1nc1ude electronic equipment (e.g.,
trip units) that compares measured input signals wit~
pre-established setpoints. When the setpoint ts exceeded, the chijnnel output relay actuates, wni ch t,hen outputs an RPS trip signal to the trip logic.
(continued)
PBAPS UNIT 2                          B 3.3-1                    Revision No. 134
 
RPS Instrumentation B 3.3.1.l
* BASES BACKGROUND (continued)
The RPS is comprised of two independent trip systems (A and B) with thl"ee logic channels i.n each*trip system (logic channels Al, A2, and A3; Bl, B2, and B3) as shm,n in the Reference 1 figures. Logic channels Al, A2, Bl, and 82 contain automatic logic for which the above 11onitored parameters each have at least one input to each of these logic channels. The outputs of the logi.c channels 1n a trip system are combined in a one-out-of-two logic so that either
                - channel can trip the associated trip system. The tripp.ing of both trip systems will produce a reactor scram. Thi.s logic arrangement is referred to as a one-out-of-two taken twice logic. In addition to the automatic logic channels, logic channels A3 and B3 (one logic channel per trip system) are manual scram channels. Both must be depressed in order to initiate the manual tri'p fuhction. Each trip system can be reset by use of a reset switch. If a full scram occurs (both trip systems trip), a relay prevents reset of the trip systems for 10 seconds after the full scram signal is received. This 10 second delay on reset ensures that the scram function wil1 be completed.
Two scram pilot valves are located in the hydraulic control unit for each control rod drive {CRD). Each scram pilot valve is solenoid operated, with the solenoids normally energized. The scram pilot valves control the air supply-to the scram inlet and outlet valves for the associated CRD.
When either scram pilot valve solenoid is energized, air pressure holds the scram valves closed and, therefore, both scram pilot valve solenoids must be de-energized to cause a control rod to scram. The scram valves control the supply and discharge paths for the CRD water during a scram,. One of the scram pilot valve solenoids for -each CRD is controlled by trip system A, and the other solenoid is controlled by trip system B. Any trip of trip system A in conjunction with any trip in trip system B results in de-energizing both solenoi.ds, air bleeding off, scram valves open.ing, and control rod scram.
The backup scram valves, which energize on a scram signal to depressurize the scram air header, are also controlled by the RPS. Additionally, the RPS controls the SDV vent and drain valves such that when logic channels Al and Bl are deenergized or when logic channel A3 is deenergized the (continued}
PBAPS UNIT 2                      B 3.3-2                      'Revision No. O
 
RPS Instrumentation B 3.3.1.1
* BASES BACKGROUND (continued) inboard SDV vent and drainc valves close to isolate the SDV, and when logic channels A2 and B2 are deenergized or when logic channel B3 is deenergized the outboard SDV vent and drain ~alves close to isolate the SDV.
APPLICABLE      The actions of the RPS are assumed in the safety analyses of SAFm ANALYSES,. References 2 and 3. The RPS is requiT'8d to initiate a LCD, and        reactor scram when monitored parameter values exceed the APPLICABILITY  Allowable Values, specified by the setpoint methodology and listed in Table 3.3.1.1-1, to maintain OPERABILITY and to preserve the integrity of the fuel cladding, the reactor cool ant pressure boundary ('RCPB) , and the containment, by
                  .minimizing the energy that ID\lst be absorbed followi.ng a LOCA.
RPS instrumentation satisfies Criterion 3 of the NRC Po1icy Statement. Functions not specifi,cally credited in the accident anal ys,i s ape retained for the over a11 redundancy and diversity of the RPS as required by the NRC approved licensing basis *
* The OPERABILITY of the RPS is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.l.l.1-1. Each Function must have a required number of OPERABLE channels per RPS trip system, with their setpoints within the speci,fied Allowable Value, where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Allowable Values, where applicable,. are specified for each RPS Function, specified in the Table. Trip setpoints are specified in the setpoint calculati.ons. The trip setpoints are selected to ensure that the actual setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setting les.s conserva~ive than the trip setpoint, but within its Allowable Value, is acceptable. A channel is inoperable if its actual trip setting is not withi.n its required Allowable Value.
Trip setpoints are those predetermined values of output at which an action should take place. lhe setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of (continued}
PBAPS UNIT 2                          B 3.3-3                      Revision No. O
 
RPS Instrumentation B 3~3.l.l
* BASES APPLICABLE SAFITY ANALYSES.
t~e process parameter exceeds the setpoint, the associated device (e .* g.,, trip unit) changes state. The analytic or LCO, and        design limits are derived from the limiting values of the APPLICABILITY    process parameters obtained from the safety analysis- or (continued)  other appropriate documents. The Allowable. Values are derived from the analytic or design 1tmits, corrected fo_r calibration, process, and instrument errors. The trip set-points 11re dete"1ined from analytical or design limits, corrected for calibration, process, and tnstrwnent errors,
* as well as instrument drift. In. selected cases, the Allowable Va1ues and trip setpo1 nts are detertn1 ned by engineering judgement or h.istorically accepted practice relative to the intended function of the trip channel. The trip setpoints determined. in this .manner provide adequate protection by assuring instrument and process. uncertainties expected for the environments during the operating _time of the associated trip channels are accounted for.
The OPERABILITY of scram pilot valves and associated solenoids, backup scram valves, and SDV valves, described in the Background section, *are not addressed by this LCO.
The individual Functions are required to be OPERABLE in the MODES  ,or ofher specified conditions specified in the Table, which-may require an RPS trip-to mitigate the consequences of a design basis accident or- transient. T-0 ensure a reliable scram functi,on, a combination of Functions are required in each MODE to provide primary and dtverse inittat1on signals.
The only MODES specified in Table 3.3.1.1-1 are MODES 1 and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. No RPS Function is required in MODES 3 and 4,. since all control rods are fu11y inserted and the Reactor Mode Switch Shutdown Position control rod. withdrawal block (LCO 3.3.2.1} does not allow any cont,rol rod to be withdrawn. In MODE 5, control rods withdrawn from a core cell containing no fuel assemblies do not affect the reactivity of the core and, therefore, are not required to have the capability to scram.
Provided all other control rods remain inserted, no RPS function is required. In this condi:tion, the required SDM (LC.O 3.1.1) and refuel position one-rod-out interlock
{LCO 3. 9_. 2) ensure that no event requiring RP$ wi 11 occur.
{continued}
* PBAPS UtHT 2                          B 3.3-4                    Revision, No. 0
 
RPS Instrumentation B 3.3.1.1
* BASES APPLICABLE        The specifk Applicable Safety Analyses, LCO, and SAFETY ANALYSES,  Applicability discusstons are listed below on. a Function by LCD, and          Furrction basis ..
APPLICABILITY
{continued)
                    ~ide Range Neutron Monitor        {WRNM}
La. Wide Range Neutron Monitor Period-Short The WRNMs provide signals to facilitate reactor scram in the event that core reactiVity increase (shortening perfod) exceeds a predetermined reference rate: -10 determine the reactor period, the neutron. flux signal is filtered. The period of this filtered neutron flux signal is used to generate. trip signals when the respective trip setpofots are exceeded. The time to trip for a particular reactor period is dependent on the filter time constant, actual period of the signal and the trip setp,oints. This period based signal is available over the er:itire. operating range from initial control rod withdrawal to full power operation. In the startup range, the most significant source of reactivity change is due to contra l rod wi thdrawa 1. The WRNM pro vi des
*                  ~
diver.se protection from t_he rod worth minimizer {RWM), which moni'tors and controls the movement of control rods at low pc;,~et_._ The~J~ prevents the withdrawal of an out of
_s~qiJel"!ce contra1 rcxr-duri rig- s-tartup 'thar*c-oulci- result 1 n* an.
unacceptable neutron -flux exca.rsion (ltef. 2). - Ttie lilRNM provides mitigation of the neutron flux excursion._ Tb demenstrate the c_apabfl 1ty of the WRNM System to ,111itigate control rod withdrawal events, an analysis has been performed (Ref. 3) to evaluate the consequences of control rod withdrawal events during .startup that. are mitigated only by the WRNM peri od-.short function. The withdrawal of a                    -
coritrol rod out of sequence~ during startup, analysis (Ref.
: 3) assumes* t_hat one WRNH channel in each trip system is bypassed, demonstrates that the WRNMs provide p.rotec.tion against local control rod withdrawal errors and results in peak fuel enthalpy below the 170 cal/gm fuel failure threshold criterion.
The WRNHs are als*o capable of limiting other reactivity excursions during startap, such as_cold water injection events, although no c.redit is specifically assumed.
(continued}
* PBAPS UNIT 2                            B 3.3-5                          - Revision No. 24
 
RPS Instrumentation B 3.3.1.1
* BASES APPLICABLE      1. a. Wide Range Neutron Hon jtor Period-Short SAFETY ANALYSES, (continued)
LCO; and APPU CAB IL ITV  The WRNM System is divided into two groups of WRNM channels, with four channels inputting to each trip system. The analysis of Reference 3 assumes that one channel in each trip system ts bypassed. Therefore, six channels with three channels in each trip system are required for WRNM OPERABILITY to ensure that no single instrument failure will preclude a scram from thiS Function on a valid signal.        '
The analysis of Reference 3 has adequate-conservatism to permit an Allowable Value of 13 seconds.
The WRNM Period-Short Function must be OPERABLE duTjng MODE 2 when control rods may be withdrawn and the potential for criticality exists. In MOOE 5, when a cell With fuel has its control rod wi,thdr.awn, the 'WRNMs provide monitoring for and protection against unexpected reactivity excursions.
In MODE 1, the APRM System and the RWM provide protection against control ro<l withdrawal error events and the WRNMs are not required. The WRNMs are automatically bypassed when
* the mode switch is in the Run position.
: 1. b. Wide Range Neutron Monitor - Inop This trip signal provides assurance that a minimum number of WRNMs are OPERABLE. Anytime a WRNH mode switch is moved to any position other than woperate,a a loss of power Qccurs, or the self-test system detects a failure which would result in the loss of a safety-related function, an inoperative trip signal will be received. by the RPS unless the WRNM is bypassed. Since only one WRNM in each trip system may be byp'assed, only one WRNM in each RPS trip system may be inopeTable without resulting in an RPS trip signal.
This Function was not specifically credited in the accident-analysis. but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
{c9ntjnyed}
* PBAPS UN IT 2.                      8 3.3-6                      Revision No. 24
 
RPS Instrumentation B 3.3.1.1
* BASES APPLICABLE SAFETY ANALYSES, LCO, and
  . APPLIGABI LITY l.b. Wide Range Neutron Monjtor-Inop (continued)
Six channels of the W~de Range Neutron Mon1tor-Inop Funct1on, with three channels 1n each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram. from this Fun ct, oh on a valid s.ignal. Since this Funct1on is. not assumed in the safety analysis, there is no Allowable Value for this Function.
This Function is required to be OPERABLE when the Wide Range Neutron Mon1tor Period,Short Function 1s required.
Average Power Range Monitor CAPRM)
The APRM channels provide'the primary indication of neutron flux within the core and respond almost instantaneously to neutron flux increases. The APRM cha.nnel s receive input Signals from the local power range monttors (LPRMs) within the reactor core to provide an indication of the power di stri buti on and local power changes. The AP'RM channels average these LPRM signals to provide a continuous indication of average reactor power from a few percent to greater than RTP. Each APRM al so includes an Osei l l ati on Power Range Monitor (OPRM) Upscale Punct1on which monitors small gro8ps of LPRM signals to detect thermal-hyd~aulic i nstab11 iti es.
The APRM System is divided into four APRM channels and four 2-out-of-4 vot~r channels. Each APRM channel provides inputs to each of the four voter channels. The four voter channels are divi~ed into two groups of two each, with each group of two providing inputs to ohe RP$ trip system. The system is designed to all ow one APRM channel, but no voter channelsi to be .bypassed.* A triP, from any one unbypassed' APRM wil result in a "half-trip' in all four of the voter channel~. but no trip inputs to either RPS trip system.
APRM tnp Functions 2.,a, 2.b, 2.c, and 2.d are voted independe~tly from OPRM Upsc~le Function 2.f. Th.er.efore, any Function 2.a, 2.b, 2.c or 2.d trip from any two unbypassed APRM channels wi 11 result in a full trip in each of the four voter channels, which in turn results in two trip 1nputs into each RPS trip system logic channe1 (Al, A2, Bl, and B2), thus resulting in a full scram signal.            .
Similarly, a Function 2.f trip from any two unbypassed APRM chann~s will result in a full trip from each of the four voter channels. Three of the f~ur APRM channels and all four of the voter cha.nnel s a re regui red to be OPERABLE to ensure that no single failure will preclude a scram on a valid signal. In addition, to provide adequate coverage of the entire core consistent with the design bases for the
                    .APRM Functions 2.a, 2.b, and 2.c, at least 2'0 LPRM inputs, with at least three LPRM inputs from each of the four axi a.l levels at wh1ch the LPRMs are located, must be operable for each APRM channel, and the number of LPRM inputs that have become inoperable (and bypassed) since the last APRM calibration CSR 3.3.1.1,2) must be less than ten for each APRM chijnnel. For the OPRM Upscale 1 Function 2.f, LPRMs are assigned to "cells" of 3 or 4 deteci:ors. A minimum of 8 cells per channel, each with a minimum of 2 OPERABLE LPRMs, must be OPERABLE for the OPRM Upscale Function 2.f to be OPERABLE.                        .
* PBAPS UNIT 2                          B 3.3-7                      Revision No. 124
 
RPS Instrumentation B 3 .. 3*.1.1
* BASES APPLICABLE      .2.a, Average Power Range Monitor Neutron Flux-High SAFElY ANALYSES, (Setdown) (continued)
LCO, and APPLICABILITY    For operation at low power (i .. e., MODE 2), the Average Power Range Monitor Neutron Flux-High (Setcfowh) Function is capable of generatihg a trip signal that prevents fuel damage resulting from abnormal operating transients 1n this power range. For most operation at low power 1evels, the Avera~e Power Range Monitor Neutron Flux-High (Setdown)
Function will provide a secondary scram to the Wide Range.
Neutron Monitor Period-Short Function because of the relative setpoir:lts. At higher power levels, it is possible that the Average Power Range Mani tor Neutron Flux-High (Setdown) Function will provide the primary trip signal for a corewide increase in power.
No specific safety analyses take direct credit for the Average Power Range Mo~itor Ne1;1tro~ F11:1x-High (Setdown)
Function. However, this Function indirectly ensures that before the reactor mode switch is pl aced in the run position, reactor power does not exceed 22.6% RTP                        I (SL 2.1.1.1) when opera1ing a~ low reactor pressure and low core fl ow. Therefore, it i ndi rectl Y" prevents fuel damage during s"ignificant reactivitY increases with THERMAL POWER
                    < 22.6% RTP .
* The Allowable Value is based on preventing significant increases in power when THERMAL POWER is< 22,6% RTP.
The Aye.rage Power Range Moni t9r Neutron Flux-High (Setdown)
Function must be OPERABLE during MODE 2 when control rods may be withdrawn since the potential for criticality exists.
In MODE 1, the Average Power Range Monitor Neutron Flux-High Function provides protection against reactivity transients ancf the RWM and rod block monitor protect against control rod withdrawal error events.
                    ~j}e  Av rage    Power Range Monitor Simulated Thermal
_Q__ r-Hi_h 9 The"Average Power Range Monitor Simulated Thermal Power-High Function monitors average neutron flux to approximate the THERMAL POWER being transferred to the reactor coolant. The APRM neutron flux 1s electronically filtered with a time constant representative of tbe fuel heat t,ransfer dynami ts to generate a signal proportional to the THERMAL POWER in the reactor. The trip level is varied as a function of recirculation drive flow (i~e., at lower core flows, the setpoint is reduced proportfonal to the reduction"in power experienced as core flow is reduced with a fixed control rod pattern) but is clamped at an upper limit that is always lower than the Average Power Range Monitor Neutron Flux-High Function Allowable Value. A note is included, app1icable when the plant is in sir:igle recirculation loop operation per LCO 3. 4 *. 1, which requires the fl ow va 1ue., used in the Allowable Value equation, be reduced by dW. The value of dW (continued)
PBAPS UNIT 2                            B 3.~-8                      Revision No. 143
 
RPS Instrumentation B 3.3.1.1 BASES AP-PLIO\BLE      2 ,b, Average Power Range Monitor Simulated Thermal SAFEJY ANALYSES, power-High (continued)
LC01 ancl APPLICABILITY    is established to conservatively bound the inaccu.racy created in the core flow/drive flow correlation due to back flow in the jet pumps associated with the inactive recirculation 1oop. The Allowable Value thus maintains thermal margins es.sentially unchanged from those for two loop operation. The value of AW is plant specific and is defined in plant procedures. The Allowable Value equatfon for single loop operation is only valid for flows down to W"" AW; the Allowable Value does not go below 60,3% RTP. This is acceptable because back flow in the inactive recirculation loop is only evident with drive flows of approximately 35%
or .g reate.r (Reference 19) .. The Nominal Trip Setpoi nt (NTSP) and the as-found and as-left tolerances (Leave Alone Zone) were determined ih accordance with Reference 10.
The Aver~ge Power Range Monitor Simulated Thermal PONer-High Function is not specifically credited in the safety analysis but is intended to provide an additiona1 margin, of protection from transient foduced fuel damage during operation where recirculation flow is reduced to below the minimum required for rated power operation. The Average Pc:Mer Range Monitor Simulated Thennal Power-High Function provides protection against transients where THERMAL POWER increases slDNlY (such~ the.loss of feedwater heating event) and protects the fuel cladding integrity by ensuring
_that the MCPR SL is not exceeded. During these events, the THffiMAL POWER increase does not significantly lag the neutron flux scram~ For rapid neutron flux increase events, the THERMAL POWER lags the neutron flux and the Average Power Range Mani tor Neutron Flux-High Function wi 11 provide a scram si,gnal before the Average Power Range Monitor ,
Simulated Thermal Power-High Function setpoint is exceeded.
Each APRM channel uses one tota1 drive flow signal representative of total <;ore flow. The total d,rive flow signal is generated by the flow processing logic, part of the APRM channel, by summing up. the flD'iA' calculated from two flow. transmitter signal inputs, one from each of the two recirculation loop flows.. The flow processing logic OPERABILITY is part of the APRM channel OPERABILITY requirements for this Function. The APRM flow processing logic is considered inoperable.when.ever it cannot deliver a flow signal less than or equal to actual Recirculation flow conditions for all steady state and transient reactor conditions while in Mode 1. Reduced or Downscale flow cond.itions due to planned maintenance or testing activities during derated plant conditions (i.e. end of cycle coast down) will result in conservative setpoints for the APRM Simulated Thermal Power-High function~ thus maintaining that
* PBAPS UNIT 2 function operable.
8 3.3-9 *
(continued)
Revision No. 143
 
RPS Instrumentation 8 3.3.1.1
* .BASES APPLICABLE SAFETY ANALYSES, LCO, and 2.b~ Average Power Range Monitor s1royJated Jhennal Power-High  (continued)
APPLICABILITY    The Allowable Value is based on analyses that take credit for the Average Power Range Monitor Simulated Therma1 Power-High Function* for the m:itigation of non-limiting events.
The THERMAL POWER time constant of< 7 seconds is based on the fuel heat transfer dynamics and provides a signal propo.rtional to the THERMAL POWER.
The Average Power Range Moni:t;o_r Simulated Thermal Power-High Function is requfred to be OPERABLE in MODE 1 when there is the possibility of gene,rating excessive THERMAL POWER and potentially exceeding the SL applicable to high pressure and core flow conditions (MCPR St). During MODES 2 and 5~ other WRNM and APRM Functions provide protection for fuel cladding integrity.
2.c. Average ~ower Range Monitor Neutron flux-High The Average Power Range Monitor Neutron Flux-High Function is capable of generating a trip signal to prevent fuel d"amage or excessive RCS pressure. For the overpressuri zat ion protection analysis of Reference- 4, the Average Power Range Monitor Neutron Flux-High Function is assumed to terminate the main ;steam iS*olatfon valve (Ms1vr-
                  -closure .event a,nd, -along with U-1e safety/relief valves (S/RVs)~ limit the peak reactor pressure vessel (RPV) pressure to less than the ASME Code ljmtts. The control rod drop accident (CRDA) aAalYsis (Ref. 5) takes c.redit for the Average Power Range Monitor Neutron Flux:--High Function to terminate- the CRDA.
(continued)
* PBAPS UNIT 2                        8 3.3-10                      Revision No. 36
 
RPS Instrumentation 8 '.3 .3. 1.1 BASES APPLICABLE      2.c. Average Power Range Monitor Neutron Flux-Hjqh SAFETY ANALYSES, (continued)      -
LCO, and APPLICABILITY    The Allowable Value 1s based on the Analytical Limit assumed ih the CRDA analysis~
The Average Power Range Monitor Neutron Flux-Hig~ Function is required to be OPERABLE in MODE 1 where.~be potential consequences of the analyzed transtents could result in the Sls (e.g., MCPR and RCS pressure) being exceeded. Although the Average Power Range Monitor Neutron Flux-High Function is assumed in the CRDA analysisj which is applicable in MODE 2, the Average Power Range Monitor Neutron.flux-High (Setdown) Function conservatively bounds the assumed trip and, together With the assumed WRNM trips, provides adequate protection. Therefore, the Average Power Range Monitor Neutron Flux-High Function is not required in MODE 2..
                                                                    <continued}
PBAPS UNIT 2                      B 3 .3-1-1                  Revision No. 36
 
RPS Instrumentation
                                                                              -s 3.3.1.1
* BASES APPLICABLE.
SAFETY ANALYSES, LCO, and
: 2. d. Average Power Range ~cmitor-I nop Three of the four APRM channels are requ.i red t-o be OPERABLE APPLICABILITY    for each of the APRM Functions, This Funct.i on ( I nop)
(continued)    provides assurance that the minimum number of APRM channels are OPtRABLE.
For any APRM channel, any time its mode switch is not in the "Operate" position, an APRM module required' to issue a trip is unplugged, or the automatic self-te~t system detects a critical fault with the APRM chai:rn~l I an Inop trip is sent to all four voter channels. Inop trips from two or more unbypas,sed APRM channels result in a trip output from each of the four voter dam1el s to it's as sod ated trip system.
This Function was not specifically credited in the accident analysis, bu,t it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved l iGensi ng basis.
There is no Allowable Value for this Function.
This Function is required to be OPERABLE in the MODES where the APRM Functions are required.
2.e. 2-0ut-Of-4 Voter The 2-0ut-Of-4 Voter Function provides the interface between the A~RM Functio~s, including_the OPRM Upsc~le_Functi9n 1 and the final RPS trip system logic. As such, 1+/- 1s require~ to be OPERABLE in the MODES where the APRM_ Functions are required and is necessary to* support the safety analysis applicable to each of those Functions. Therefore, the 2-0ut-Of-4 Voter Function needs to be OPERABLE in MODES 1 and 2.
All foUT voter channels. are required to be OPERABLE. Ea*c~
voter channel incl,udes self-9iagm>stic fun~tions. If any voter channel detects a cr1t1cal fault 1n rts own processing, a trip is issued from that voter cha,nne-l to the associated trip system.
The 2-0ut-Of-4 Logic Module includes 2-0ut-Of-4 Voter hardware and the APRM Interface hardware. The 2-0ut~Of-4 Voter Function 2.e votes APRM Functions 2.a, 2.b, 2.c and 2.d iridependently of Function 2.f. This voting is accomplished by the 2-0ut-Of-4 Voter hardware in the 2-0ut~Of-4 "Logic Module.
Each 2-0ut-Of-4 Voter includes two re-dunda.nt sets of outputs to R~S. [ach output set contains two indep~ndent contacts; one contact for Functions 2.a, 2.b, 2.c and 2.d, and the other contact for Function 2.f. The analysis in Reference 12 took credit for this red_undancy in the justif-icgtion of the 12-hour Completion Time for Condition A, so the voter Function 2,e must be declared inoperable if any of its functionality is inoperable. However, the voter Functio*n 2.e does not need to be declared inoperable due to any failure affecting only the plant interface portions of the 2-0ut-Ofr4 Logic Module that are not necessary to perform the 2-0ut-Of-4 ijoter function.
There is n~ Allow 9 ble Value for this Function.
PBAPS UN IT 2                      B 3 .3-12                      Rev'i si on No. 50
 
RPS Instrumentation B 3.3.1.1
* BASES APPLICABLE SAFETY ANALYSES, LCO, and 2.f. Oscillation Power Range Monitor COPBM) Upscale The OPRM Ups cal,e Function provides comp 1i ance with 10 CFR APPLICABILITY    50, Appendix A, General Design Crit~ria (GOC) 10 and 12, (continued)  thereby providing protecti.on from exceeding the fuel MCPR safety limit (SL) due to anticipated thermal-hydraulic power oscillat-ions.
Reference 22 describes the Detect and Suppress-Confirmation Density (DSS-CD) long-term stability solution cl.iid the licensing b_asis Confinnation Density Algorithm (COA). Reference 22 also describes the .DSS-CD Armed Region and the three additional algorithms for detecting thermal-hydraulic instability related neutron flux oscillations: the period based detection algorithm (PBDA), the amplitude based algorithm CABA), and the growth rate algorithm (GRA). All four algorithms are implemented in the OPRM Upscale Function, but the safety analysis takes credit only for the CDA. The remaining three algorithms provide defense-in-depth and additional protection against unanticipated oscillations. OPRM Upscale Function OPERABILITY is based only on the CDA *.
The OPRM Upscale Function receives input signals from the local poWer range monitors (LPRMs) within the reactor core, whi.ch are combined into cells for evaluation by the OPRM algorithms.
DSS-CD operability requires at least 8 responsive OPRM cells per channel. The DSS-CD software. includes a self-check' for the responsive OPRM cells: therefore, no ?R is necessary.
The OPRM Upscale Function is requi red to be OPEAABLE when the plant is ~ 17:6% IUP, which is established as a power level that is greater than or equal to 5% belo,., the lower boundary of the Armed Region. This requirement is designed to encompass the region of pewer-flow operation where anticipated events could lead to thennal-hydraulic instability and related neutron flux oscillations. The OPRM Upscale Function is automatically trip-enabled wher:i THE.RMbiL P'ER, as indicated by the APRM Sillll:llated Thermal PONer, is~ 22.6% RTP corresponding to the MCPR monitoring threshold and reactor recirculation cirive flow, is less than 75% of rated flow. This region is the OPRM Anned Region. Note (h) allOiiS for entry into the 055-CD Armed Region without automatic arming of DSS-CO prior to cOl11)letely passing through the DSS-CD Armed Region during the first .startup and the first shutdown fo 11 owing DSS-CD i mp.1 ementation.
(continued)
PBAPS UNIT 2                          B 3.3-12a                        Revision No. 143
 
RPS Instrumentation
                                                                                .B 3.3.1.1 BASES APPLICABLE      2,f. Oscillation Power Range Mor:1jtor COPRM)
SAFETY ANALYSES, Upscale (continued)
LCO, and APPLICABILITY    As described in Refe-rence *22 and 24, the RTP values for the OPRM Upscale Function to be OPERABLE.~ 17.6% RTP) and for the OPRM Upscale Function to be auto-enabled~ 22.6% RTP) ~re
                  ,sufficiently conservative for l)rotection of the. plant against thennal-hydraulic instabilities. The basis for the S% RTP difference between the OPRM Upscale OPERABLE (17.6% RTP) and OPRM Upsca1e auto-enable 'ilalue (22.6% RTP) is to ensure tfuat no credible event, e.g., Toss of feed water heating, could result in a plant po.ver excursion where an inoperable OPRM channel entered into the OPRM Armed Region. Peach Bottom plant specific analyses performed at these 1()\,1/ power 1eveJs (Reference 24) have demonstrated that any power excursi.on-resulti.ng from credible events is bounded by 5% RTP. In addition, both the core-wide and channel decay ratios at the OPRM Upscale auto-enabled values are extremely l<M' as documer:ited in Refere,ice 22 ,. which dem5nstrates the low possibility of thennal-hydraulic instabilities at low power and-conftnns the conservatisms in the OPRM Upscale function auto-enable RTP va1ue:. The conservatisms in the determination of tt:ie values for OPRM Upscale Function OPERABLE -and the OPRN Upscale Function auto enabled sufficiently compensate for possible inaccuracy of the APRM simulated thermal power signal versus actual core thermal power at l)O\'t'er levels<. 22.6% RTP .
Therefore, there is no need to perfonn any calibration of the APRM simulated thermal J;)()ll,lei sign 91 to calculated power with RTP < 22.6% in order to determine the OPRM Upscale Function OPERABLE.
If any OPRM auto-enable setpoirit is in a non-conservative condition, i.e., the OPRM Upscale is not auto-enabled w,~th RTP
                    ~ 22.6% and reactor recirculation drive flow :S 75% of rated, the associated channel is considered inoperable for the OPRM Upscale function. Alternatively, the auto-enable setpoint may be adjusted to place the chcU1nel in a conservative condition Canned). If placed in the armed condition, the channel is considered OPERABLE.
Note (h) reflects the need for plant data collection in order to test the DSS-CD equipment. Testing the DSS-CD equipment ensures its proper operation and prevents spurious reactor trips. Entry into the DSS-CD Anned Region without automatic arming of oss-co, during this initial testing phase also allows for changes in plant operations to address maintenance or other operatioAal needs. However, during this initial testing period, tbe OPRM Upscale Function is OPERABLE and DSS-GD operability and capability* to automatically arm sha1l be maintained at recirculatioo drive flow rates above the DSS-CO Armed Region flo,; boundary.
(continued)
* PBAPS UNIT 2                        B. 3.3-12b                        Revision No. 143
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE      2.f. Oscillation Power Range Monitor (OPRM)
SAFETY ANALYSES, Upscale (continued)
LCO, and APPL! CABI LITY  An OPRM Upscale trip is issued from an OPRM channel when the confirmation density algorithm in that channel detects oscillatory changes in the neutron flux, indicated by periodic confirmations and amplitude exceeding specified set points for a specified number of OPRM cell's in the channel. An OPRM Up,scal e trip 1s al so issued from the channel if any of the defense-in-depth algorithms (PBDA. ABA, GRA) exceed their trip condition for one or more cells in that channel.
Three of the four channels are required to be operable. Each channel is capable of detecting thermal-hydraulic instabilities, by detecting the related neutron flux oscillations, and issuing a trip signal before the SLMCPR is exceeded. ihere is no Allowable Value for this function.
The OPRM Upscale Function is not LSSS SL-related (Ref. 22) and Reference 23 confirms. that the OPRM Upscale r&deg;unct1 on
* settings based on DSS-CD also do not have traditional instrumentation setpoints determined under an instrument setpoint methodology.
(continued)
* PBAPS UNIT 2                        B3.3-12c                      Revision N '. 123 I
 
RPS Instrumentation B 3.3.1.l
* BASES APPLICABLE SAFETY ANALYSES,
: 3. Reactor Pressure-High LCO, and            An  increase. in the RPV prt!ssure during reactor operation APP LI CAB! LITY    compresses the steam voids and results in a positive (continued)      reactivity insertion. This causes the neutron flux and THERMAL POWER transferred to the reactor coolant to increase, which could challenge the integrity of the fuel cladding and the RCPB. No specific safety analysis takes direct credit for this Function. However, the Reactor Pressure-High Function initiates a scram for transients that result in a, pressure increase, counteracting the pressure increase- by rapidly reducing core power. For the
                  - overpressurization protection analysis of Reference 4, the Reactor Pressure-High Function is credited as a backup Scram Function only.* The analyses conservatively *assume the scram occurs on the Average Power Range Monitor Stram Clamp signal, not the Reactor Pres.sure-High signal. The reactor.
scram, along with the S/RVs, limits the peak RPV pressure to 1ess than the ASHE Settioh III Code 1 imits.
High reactor pressure signals are initiated from four pressure transmitters that sense reactor pressure. The Reactor Pressure-High Allowable Value f,s chosen to provide a sufficient margin to the ASME Section III Code limits
* durtng the event~ *
* Four channels of Reactor Pressure-Hjgh Function, with two channels in each trip system arranged in a one-'Ollt-of-two logic, are required to be OPERABLE to ensure that no s.ingle instrument failure Will preclude a scram from this Function on a valid signal. The Function is required to be OPERABLE in MODES 1 and 2 when the RCS is pressurized arid the potent 1a1 for* pres.sure increase exists.
: 4. Reactor Yesse1 Water Leve1 -Low <Leve1 3 l Low RPV water level indicates the capability to cool* the fuel may .be threatened. Should RPV water level dectease. too far, fuel damage could result. Therefore., a reactor scram is initiated at Level 3 to substantially reduce the heat generated in the fuel from fission. The Reactor Vesse1 Water Level-Low (Level 3) Function 1s assumed in the analysis of events resulting in the decrease of reactor coolant inventory (Ref. 6). This is credited as a backup scram function for large and intermediate break LOCAs inside
* PB!\PS UNIT 2                          B 3.3-13
{continued)
Revision No. O
 
RPS Instrumentation B 3.3.1.l
* BASES APPLICABLE
* SAFETI ANALYSES,
: 4. Reactor Vessel Water leyel-Low (Level      .3)  (continued)
LCO, and          primary conta.i nment. . The reactor scram r,educes the amount APPLICABILITY    *of energy requtred to be absorbed and,. along with the actions of the Emergency, Core Cooling Systems (ECCS),
ensures th~t the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Reactor Vessel Water Level -Low ( Leve1 3) signals    a.re initiated from four level, transmitters that sense    the difference between the pressure due to a constant      column_ of water (reference leg) and th_e pressure due to the      actual water level (variabl,e leg) in the vessel.
Four channels of Reactor Vessel Water Level-Low (Level 3)
Function, with two channels in each trip system arranged in a one-out-of-two logic,. are required to. be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.
The Reactor Vessel Water Level-Low (Level 3) Allowable Value is selected to ensure that during nonna1 Operation the s-eparator skirts are not uncovered (this protects available reci~ulation pump net positive suction head (NPSH) frQm significant carryunder) and,- for transients involving loss of all nonnal feedwater flow, initiation of the low pressure ECCS subsyste111S at Reactor Vessel Water-Low Low Lro.w
( Leve1 I) will not be required_, .. . .
                    ~The Function is required in MODES' I and 2 where considerable energy exists in the RCS resulti.ng in the limiting transients and accidents. ECCS initiations at Reactor Vesse.1 Water Level-Low Low (Level 2) and Low Low Low
                      .(Level I) provide sufficient protection for level trans*ients in a1l other MODES.
: 5. Main Steam rsolatjon Valve-Closure MSIV closure results in loss of the main turbine and the condenser as a heat sink for the nuclear steam supply system and indicates a need to shut down the reactor to reduce heat generation. Therefore,, a reactor scram is initiated on a, Main Steam Isolation Valve-Closure signal before the MSIVs are completely closed in anticipation of the complete loss of the normal heat sink and subsequent overpressur1zation
* PBAPS UNIT 2                          B 3.3-14 (continued)
Revision No. O
 
RPS Instrumentation B 3.3.1.1
* BASES APPLICABLE      5.
* Main Steam Isolation Valve-Closure    (continued)
SAFETY ANALYSES, LCO, and        transient. However, for the overpressurtzat 1cm protect ion APPLICABILITY    analysis of Reference 4, the Average, P~er Range Monitor Scram Clamp Function, al,ong with the S/RVs, limits the peak RPV pressure to less than the ASHE Section III Code limits ..
That is, the direct scram on position switches for MSIV closure events is not assumed in the overpressu.rization analysis. The reactor scram reduces the amount Of ene.rgy required to be absorbed and, a1ong with the actions of the.
ECCS,. ensures that the fuel peak cl adding temperature remains below the limits of 10 CFR .50.46.
MSIV closure' signals are initiated from position switches located on each of the eight MSIVs. Each MSIV has two position switches; one inputs' to RPS trip system A wh i1 e the other inputs to RPS trip ~ystem B. Thus, each RPS trjp system receives an input from eight Main Steam Isolation Va 1ve-Cl osure channe 1s, each consisting of one posit ion switch. The logic for the Main Steam Isolation Valve-Closure Function is arranged such that either the inboard o.r outboard va'lve on three or more of the main steam 1 ines must close in order fo.r a scram to occur. Ir:i addition, certain combinations of valves closed in two lines will result in a half-scram.
The Main Steam Isolation Valve-Closure Allowable Value is specified to ensure that a scram occurs prior to a significant reduction in steam flow, thereby reducing the severity of the subsequent pressure transient.
Eight channels of the Main Steam I'solation Valve-Clos-ure Function, with four channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude the scram from this Function on a valid signal. This Function is only required in MODE I si,nce, with the MSIVs open and the heat generation rate.
high,*a pressurization transient can occu.r if the MSIVs close. In MODE 2., the heat generation rate is low enough so tha_t the other di.verse RPS functions provide sufficient protect fen.
{continued}
PBAPS UNIT 2                        B 3.3-15                    Revision No. 0
 
RPS Instrumentation 8 3.3.1.1
* BASES APPLICABLE      6. Drvwell Pressure-High SAFETY ANALYSES, LCO, and        High pressure in the drywell could indicate a break in the APPL! CABl LITY  RCPB. A reactor scram is initiated to minimi.ze the (continued}  possibility of fue 1 damage anct to reduce the amount of energy being added to the coolant and the drywell. The Drywell Pressure-High Function is assumed to scram the reactor during large and intermediate break LOCAs inside primary containment. The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the .fuel peak cladding temperature remains below the li111ts of IO CFR 50.46.
High drywall pressure signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as poss,ible and indicative of a LOCA inside primary containment.
Four channels of Drywall Pressure-High Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensu,re that no .si.ngle instrument failure will preclude a scram. from this Function on a valid signal. The Function is required in MODES I and 2 where considerable energy exists in the RCS, resulting in the -1 i mi t 1ng- -transients and ace i dents.
Z, Scram Di scha.rge Volume Water Level -High The SDV receives the ,water di.splaced by the motion of the CRD pistons during a reactor scram. Should this volume fill to a point where there is insufficient volume to accept the displaced water, control rod insertion would be hindered.
Therefore, a reactor scram is initiated while the remaining free volu111e is still sufficient to accommodate the water from a full core scram.. No credit is takeh for a scram initiated from the Scram Discharge Vol I.IIDe Water Level -High Function for any of the design basis accidents or transients analyzed in the UFSAR. However, this function is retained to ensure the RPS remains OPERABLE.
(continued)
* PBAPS UNIT 2                            B 3.3-16
(
Revisi.on No. 0
 
RPS Instrumentation B 3.3.Ll
* BASES
  *APPLICABLE      7. Scram Discharge Volume Water Level-High      (continued)
SAFETY ANALYSES, LC0, and        SDV water level is measured by two di verse methods. The APPUCABI LITY    level i~ measured by two float type level switches and two thermal probes for a total of four level signals, The outputs of these devices are arranged so that one switch provides i.nput to one Rl?S 7og1 c ch.annel. The level measurement i nstrumentati orr saJi sfi es the recommendations of Reference 8.
The .Allowable ValLte is chosen 1ow enough to ensure that there is sufficient volume in the SDV to accommodate the water from a full scram .
Four high water level inputs to the RPS from four switches are required to be OPERABLE, with two switches in each trip system, to ensure that no single instrument failure will preclude a scram from this Function on a vc11id sig*nal. This Function is required in MODES 1 and 2, and in MODE 5 with any control, rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other s pee if 1ed conditions when control rods a re withdrawn. At all other times, this Function may be. bypassed.
: s. Iurbine    Stop Valve-Closure Closure of the TSVs reswlts in the loss of a heat sink that produces_ reactor pressure, neutron flux, and heat flux, transients that must be limited. Theref~re, a reactor scram is initiated at the start of TSV closure in anticipation of the transients that would result from the clo~ure of these valves. The Turbine Stop v,alv.e-Closure F"unction is th prima~y scram signal for the tu~bine trip event analyzed in Reference 7 and the feedwater controller failure event. For these events, the reactor scram reduces the amount of energy required to be absorbed and ensures that the MCPR SL is not ex.ceeded.
Turbine Stop Valve-Closure signijls are initiated from fo~r position switches; one located on each of the four TSVs.
Each switch provides two input signals; one to RPS trip_
s_ystem A and the other, to RPS trj p system B. Thus, e.ach RPS trip system rece.i ves an input from four Turbine Stop Valve-Closure channels. The logtc for the Turbine Stop
* PBAPS UN IT 2                        B 3.3-17                        Revision No. 87
 
RPS Instrumentation B l.3.1.1 BASES APPLICABLE      8. Turbine Stop Va]vti]osyre (continued)
SAFETY ANALYSES, LCO, and        Valve-Closure Function is s~ch that three or more TSVs must APPLICABILITY    be. closed to produce a scram. In addition, certain combinations of two valves closed will result in a half-scram. This Function must be enabled at THERMAL POWER
                  ~ 26.3% RTP as measured at the turbine first stage pressure.
This is normally accomplished automatically by pressure switches sensing turbine fir'st stage pressure; therefore, opening of the turbine bypass valves may affect this Function.
The Turbine Stop Valve-Closure Allowable Value is selected to be high enough to detect imminent TSV closure, thereby reducing the severity of the subsequent pressure transient.
Eight channels of Turbine Stop Valve-Closure Function, with four channels in each trip system, are* required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function if ar:1y three TSVs should c1ose. This Function i.s required, consistent with analysis assumptiQns, whenever THERMAL POWER is~ Z6.3% RTP. This Function is not required when THERMAL POWER is< 26.3% RTP si nee the Reactor Pressure- High and the Average Power Range Mani tor Scram Cl amp Functi ans are adequate to ma:i ntai n the necessary safety margins.
9, Turbine Control Valve Fast Closure, Trio 0;1 Pressure:-Low Fast closure of the TCVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. The.refore, a reactor scram is initiated on TCV fast closure in anticipation of the transients that would result from the clos\lre of these valves. The Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Function is the primary scram signal for the generator load rejection event analyzed in Reference 7 and the generator load rejection with bypass failure event. For these e.vents, the reactor scram reduces the amo1:1nt of energy required to be absorbed and ensures that the MCPR SL is not exceeded.
(continued)
* PBAPS UNIT 2                      B 3~3-18                    Revis.ion No. 143
 
RPS Instrumentation B 3.3,1.1
* BASES APPLICABLE      9. Jurbjne Control Valve fast Closure,, Trio Oil SAFETY ANALYSES, Pressure-Low (continued)
LCO, and APPLICABILITY    Turbine Control Va]\le Fast_ Closure, Trip Oil Pressu.re-Low signals are initiated by the relayed emergency trip supply oil pressure. at eac;h control valve. One pressure switch fs associated with each control valve, and the signal from each switch is assigned to a separate RPS logic channel. Th1s Function mast be enabled at THERMAL POWER~ 26.3% RTP. This is normally accomplished automaticall~ by pressure switches sensing turbine first stage pressure; therefore, opening of the turbiae bypass valves* may affect this Function.
The Turbine Control Valve Fast Closure., Trip Oil Pressure-Low Allowable Va.lue is selected high ehough to detect imminent TCV fast closure.
Four channels of Turbine Control Valve Fast C1osure, Trip Oil Pressure- Low Function with two channels in each trip system arranged in a oi:ie-out-of-two logtc are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This Function is req~ired, consistent with the analysis assumptions, whenever THERMAL POWER is" ';?! 26. 3% RTP. Toi s Functi orr is not req"iii red when THERMAL -POWER is < 26. 3% RTP, since the Reactor Pressure-High and the Average Power Range Monitor Scram Clamp Functions are adequate to maintain the necessary safety margins.
: 10. Turbine Condenser-Low Vacuum The Turbine Condenser-Low Vaeu1:1m Function protects the integrity of the main conder:iser by scramming the reactor and thereby decreasing the sevetity of the low condenser vacuum transient on the condenser. Thi.s fu11ction also ensures integrity of the reactor due to loss of its normal heat sink. The reactor scram on a Turbine Coadenser-Low va~uum signal will occur prior to a reactor scram from a Turbine S.top Valve-Closure signal. .. This fynction is not specifically credited in any accident analysis but is being retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
(continued)
* PBAPS UNIT 2                        B 3.3-19                      Revision No. 143
 
RPS lnstrumentat1oA B 3.Ll.1
* BASES APPLICABLE      10,  Turbj ne ConoensecLow Vacu:um    ccont1 nued l SAFETY ANALYSES, LCO, and        Turbine Condenser-Low Vacuum signals are irrit1ated from APPUCA8I LITY    four vacuum pressure transmitters that provide inputs to associated trip systems. There are two- trip systems and two channels per trip system. Each trtp system 1S arranged 1n a one-out-of-two logfc and bot~ trip systems must be tripped 1n order to scram t'he reactor.
The Turbine Condenser-~ow Vacuum Allo~able Value is spec1 f1 ed to ensure that a scram occurs pr1 or to the integrtty of the main condenser being breached, thereby limiting the damage to the normal heat sink of the r.eactor.
rour channels of the Turbine Condenser-Low Vacuum Function w1th two Chann~ls in each trip system, are required to be OPERABLE to ,ensure that no single instrument failure w111 preclude a scr*am. from this function on a valid signal. This Function is only required in MODE 1 where cunsiderable energy ex1 sts which could, cha 11 enge the integrity .of the main condenser ff vacuum 1s low. In MODE 2, the Turbine Condenser-Low Vacuum Functior:i 1s not required becatise at low power levels the transients are less severe~
: 11. De) eted Cconttnued)
PBAPS UNIT 2                        B 3.3-20                      Revision No. 134
 
RPS Instrumentation B 3.3.I.l
  ,BASES APPLICABLE      12, Reactor Mode Switch-Shutdown Position SAFETY ANALYSES, LCO, and        The Reactor Mode Switch-Shutdown Pos1t1on Function provides APPl.ICABI LITY  signals, via the manval scram logic channels, directly to the scram pilot solenoid power circuits. These manual scram logic channels are redundant to the automatic protective instrumentation channels and provide manual reactor trip c~pabi11ty. This Function was not specifically credited in the accident analysis, but it fs retained for the overall redundancy and diversity of the RPS as required by the NRC approved 11censtng oasis.
The reactor mode switch is a key7ock four~position, four-bank switch. The reactor mode switch 1S capable of scramm.ing th.e reactor if the mode switch is p.laced in the shutdown position. Scram signals from the mode switch are input into each of the two RPS manual scram logic channels.
There is no Allowable Value for this Function, since the channels are mechanically actuated based solely on reactor mode switch position.
Two channels of Reactor Mode-Switch-Shutdown Position Function, with one channel tn each manual scram tr1p system, are available and required to be OPERABLE. The Reactor Mode Switch- Shutdown Pos 1t ion Fun ct 1on 1s required to be OPERABLE 1n MODES 1 'and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.
                                                                          <continued}
PBAPS UNIT 2                      B 3.3-21                      Revision No. 134
 
RPS Instrumentation B 3.3.1.l
* BASES APPLICABLE      13. Manual Scram SAFITY ANALYSES, LCO, and        The Manual Scram push button channels provide signals, via APPUCABILITY    the manual-scram logic channels, directly to the scram pilot (continued)  solenoid power circuits. These manual scram logic channels are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
There is one Manual Scram .push button channel for each of the two RPS manual scram logic channels. In order to cause a scram it is necessary that each channel in both manual scram trip systems* be actuated.
There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.
Two channels of Manual Sc.ram with one channe 1 in each manua 1 scram trip system are available and required to be OPERABLE in HODES 1 and 2, and in MODE 5 with any.control rod withdrawn from a core cell contai,ning one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.
14,  RPS Channel  Test Swjtch There are four RPS Channel Test Switches, one associated With each of the four automatic scram logic channels (Al, A2, B1, and 82)
* These key l ock switches a11 ow the opera tor to test the OPERABILITY of each individual logic channel without the necessity of usi.ng a scram function trip. This is accoll1J)lished by placing the RPS Channel Test Switch in test, which will input a trip signal into the associated RPS logic channel. The RPS Channel Test Switches were not specifically credited in the accident analysis. However, because the Manual Ser.am Functions at Peach Bottom Atomic Power Station, were not configured the same as the generic model in Reference 9, the RPS Channel Test Switches were included in the analysts in Reference 10. Reference 10 concluded that the Surveillance Frequency extensions from
{continued)
PBAPS UNIT 2                        B 3.3-22                    Revision No. O
 
RPS Instrumentation
      -....,..__.........,, __ ,...-_~,.. ,._..,_ -- --------.-------                                          B 3.3.1.1 BASES APPLICABLE                                          14. RPS Channel Jest Switch  Ccontinued)
SAFETY ANALYSES, LCD, and                                          RPS Functionsr described in Reference 9, were not affected APPUCABI LI.TY                                      by the difference in configuration, since each automatic RPS channel has a test switch which is functionally the same.as the manual scram- switches in the generic model. As such, the RPS Channel Test Switches are retained in the Technical Speci fi cations.
There is no Allowable Value for this Functio~ since the channels are mechanically actuated based solely on the posit 1on of th,e switches.
Four channels of RPS Channel Test Switch with two channels in each tr1p system arranged in a one-out-of-two logic are available and required to be OPERABLE in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core eel l containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods a re withdrawn.
* ACTIONS                                            Note 1 has been provided to modify the ACTIONS related to RPS instrumentation channels. Seel ion 1. 3, Gornp1 et ion Times, specifies that once a Condition has teen entered, subsequ,errt di visions, subsystems .. components, or va ri ab1 es expressed in the Condition, discovere~ to be inoperable or not within limits.~ will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure. with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperab1e RPS instrumentation channels provide appropriate comp ens a to ry measures for separate i nope ra b1e cha nne 1s. - As such, a Note has been provided that allows separate Condition entry for each inoperab1e RPS instrumentation
                                                    ,channel, Note 2 has been provided to modify the ACTIONS for the RPS instrument,ation fu:rrctions of APRM flow Biased Neutron-Flux High (Function 2.b.) and APRM Fixed Neutron Flux-Hi.gh (Function 2.c) when they are inoperable due to fa1]ure of SR 3.3.1.1.2 and gajn adjustments are necessary. Note 2 allows entry into associated Condittons and Required Actions to be delayed for up to 2 hours i_f the APRM is indicating a lower
* power value than the calculated power (i.~., the gain adjustment factor (GAF) is high Cnon-conserv:att ve)). The GAF for any channel fs defined as t~e power value determined PBAPS UNIT 2                                                            B 3.3-23                      Revision No. 149
 
RPS Instr'Umentatton
                                                                    '8 3.3.1.1
* BASES ACTIONS      (continued) by the heat balance divided by the APRM reading for that channel. Upon completion of the gain adjustment, or expiration of the allowed time, th.e channel must be returned to OPERABLE status or the applicible Condition ent~red and the Required Actions taken. This Note is based on the time required to perform gain adjustments on multiple ch~nnels.
A.1 ahd A.2 Because of the diversity of sensors available to 'provicrte trip signals and the redundancy of the RPS design, an a1lowable out of service time of 12 hours has been shown to be acceptable (Refs. 9, 12 & 13) to permit restoration of any 1noperabl e channel to OPERABLE status. However, this out of service ti_me is only acceptable provided the associated
* PBAPS UNJT 2                  B 3.3-23a                  Revision No. 149
 
RPS Instrumentation B 3.3.Ll
* BASES ACTIONS      A,l and A.2 (continued)
Function's inoperable channel is in one trip system and the Function still maintains RPS trip capability (refer to Required Actions B.1, B.2, and C.1 Bases). If the inoperable channel cannot be restored to OPERABLE stafos within the allowable out of service time, the channel or.t-he associated trip system must be placed in the tripped condition per Required Actions, A.1 and A.2.. Placing the inoperable channel in trip (or the associated trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failur~. and allow operation to contiriue. Alternatively, if it is not desired to place the channel (or trip system) in trip (e.g.,
as in the case where placing* the inoperable channel in trip wo~ld result in a full scram), Condition D must be entered and its Required Action taken.
As noted, Act1on A.2 is not applicable for APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f. Inoperability of one required APRM channel affects both trip systems. For that conditi.on,
* Required Action A.1 must be satisfied, and is the only action (other than restoring operability) that will restore capability to accommodate a single failure. Inoperability of more than one required APRM channel of the same trip function results 'in loss of trip .capabiLity and entry into Condition C, as well as entry into Condition A for each channel.
B.1 and B.2 Condition B exists when, for any one or more Functions, at least one required channel is inoperable in each trip system. Jn this condition, provided at least one channel per trip system is OPERABLE, the RPS still maintains trip capability for that Function, but cannot accommodate a single failure in either trip system.
Re,quired Actions B.l and B.2 limit the time the RPS scram logic, for any Function, would not accommodate single failure in both trip systems (e.g., one-out-of-one and one-out-of-one arransement for a typical four channel Function). The reduced reliability of this lo(Jic arrangement was not evaluated in References 9, 12 or 13 for the 12 hour Completion Time. Within the 6 hour allowance, the associated Function will have all required channels OPERABLE or in trip (Or any combination) in one trip system.
PBAPS UN IT 2                  B 3.3-24
 
RPS Instrumentation
                                                                                  , B 3.3.1.1
* BASES ACT IONS    8.1 and B.2 (continued)
Completing one of these Required Actions restores RPS to a reliability level equivalent to that evaluated in References 9. 12 or 13, which justified a 12 hour allowable out of service time as presented in Condition A. The trip system 'in the more degraded state should be placed in trip or. alternatively, all the inoperable channels in that trip system should be placed in trip (e.g., a trip system with two inoperable channels could be in a more degraded state than a trip system with four inoperable channels if the two inoperable channels are in the same Function while the four i nope r ab l e ch a nne l s a re all i n d i ff e rent Fun ct i on s ) . Th e decision of which trip system is in the more degraded state sh,oul d be ba.sed on prudent judgment and take into account current plant conditions (i.e., what MODE the plant is in).
If this action would result in a scram or RPT, it is permissible to place the other trip system or its inoperable channels in trip.
The 6,hollr Completion Time is judged acceptable based on the remaining capability to trip, the diversity,of the sensors available to provide the trip signals, the low probability of extensive numbers of inoperabilities affecting all di verse Functi d'ns, and the low probability of an event r e qui r j ng t he i nH i a ti on of a - s c ram . --
Alternately, tf it is not desired to place the inoperable channels (or one trip system) in trip (e.g., as in the case where placing the inoperable channel or a~sociated trip system in trip would result in a scram, Conditiot:1 D must be entered and its Required Action taken.
As noted, Condition Bis not applicable for APRM Functions 2.a, 2.. b, 2.c, Z.d, or 2.f. Inoperability of an APRM channel affects both trip sys,tems and is not associated with a s.peci fi c trip system as a re the APRM 2-0ut-*Of-4 voter and other non-APRM channels for which Condition B applies. For an inoperable APRM channel, Required Action .A.l must be satisfied, and is the only action {other than restoring operability) that will restore capability to accommodate a single failure. Inoperability of a Function in more than one required APRM channel results in loss of trip capability fo r th at Fu nct i on a nd en t r y i nto Co ndit i on C, as well a s en t r y i nto Con di ti oh A fo r e ac h c ha nne l . Be ca us e Con di ti on A and C provide Required Actions that are appropriate for the inop,erability of APRM Functions 2.a, 2.b, 2.c, 2,d, or
: 2. f, and these functions a re not associ .ated with specific trip systems as a_re the APRM 2-0ut-Of-4 voter and other non~
APRM channe1s, Condition B does not apply.
* PBAPS UNIT 2                        B  3.3-25 C
Revision No. 50 I,
 
RPS Instrumentation B 3.3.1.1 BASES ACTIONS        Ll (continued)
Required Action C.1 is iFJtended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same trip system for the same Function
                  .result in an automatic Function, or two or more manual Functions, not maintaining RPS trip capability. A Functio~
is considered to be maintaining RPS trip capability when sufficient channels are OPERABLE or fn trip (or the associated trip system is i'n trip), such that both trip systems will genel"ate a trip signal from the given Function on a v~lid signal. For the typical Function with_one-out-of-two taken twice logic and the IRM and APRM Functions, this would require both trip systems to have one channel OPERABLE or in trip (or the associated trip system in trip).
For Fyriction 5 (Main Steam Isolation Valve-Closure), this wou1d require both trip systems to have each channel associated with the MSIVs in three main steam lines (not necessarily the same main stea-tn lines for both trip systems)OPERABl:.E or in trip (or the associated trip system in trip). For Function 8 (Turbine Stop Valve-Closure),
this would require both trip systems to have three channels, each OPERABLE or in trip {or the as*sociated trip system in
                -trip). For Functions ]2-* (Reactor*Mode Swttch -Strutdown Position) and 13-(Manual*Scram), this would*requlf'\e both trip systems to have one channel, each OPERABLE or in trip (or the associated trip system in trip).
The Completion r*i me is intended to a11 ow the operator ti me to evaluate and repair any discovered inoperabilittes. The 1 hour Completion Time is acceptable because it minimizes rfsk while allowing time for restoration or tripping of channels.
* Q.J Required Action D.1 dtrects entry into the approprhte Coridit ion referenced in Table 3. 3. I. 1-1. The applfcabl e condition specified in the Table is Function and MODE or other specified co.ndition dependent and may change as the Required Action of a previous Condition is completed. Each time an inoperable channel has not met any Required Acthm of Condition A, B, or C and the associated Completion Time has exp*ired, Condition D will be entered. for that channe1 and provides for transfer to ttre appropriate subsequent
* PBAPS UNIT 2 Condition.
B 3.3-26
                                                                        <continued)
Revision No. 36
 
RPS Instrumentation
                                                                        *B3.3.1.1 BASES ACTIONS      E,1. F,l and G.l (continued)
If the channel Cs) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completfon Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. The allowed Completion Times are reasonab1e, based on operating experience, to reac~ the speti fi ed condi tfon from full power conditions in an order1 y manner and without ch all erigi ng pl ant systems. In add Hi on, the Completion Time of Required Action E.1 is consistent with the Completion Time provided in LCD 3.2 .. 2, "MINIMUM CRITICAL POWER RATIO (MCPR)."
1:L..1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system pl'aced in trip} within the allowed Completion T1me, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by immediately i niti ati ng action to ful1y inse.rt all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing rro fuel assemblies do not affect the reactivity of the <::a.re and are, therefore, not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.
Ll If OPRM Upscale trip capability is not maintained, Condition I exists and Backup Stability Protection (BSP) is required.
The Manual BSP Regions are described in Reference 22. The Manual BSP Regions are procedurally establisned consistent with the guid~lines identified in Reference 22 and require specified manual operator actions if certain predefined opera ti anal cond.i ti ans occur ..
The Completion Time of immediately is based on the importance of limiting the period of time during which no automatic or alternate detect and suppress trip capabil1ty is in place.
r.2 and I.3 Actions t.2 and I.3 are both required to be taken in conjunction with Action Ll if OPRM Upscale trip capability ts not maintained. As described in Section 7.4 of Reference 22, the Automated BSP Scram Region is designed to avoid reactor instability by automatically preventing entry into PBAPS UNIT 2                      B 3.3-27                    Revision No. 123
 
                                                                ~PS Instrumentation
                                                                            .B 3.3.1.1 BASES ACTIONS        1,2 and I~3      (continued) the region of the power and fl ow- ope rat i hg map that is susceptible to reactor instability. The reactor trip would be initiated by the m0d~ffed APRM Simulated Thermal Power-High scram setpoints for flow reduction events that would have terminated in the Ma:nual BSP Region I, The Automated BSP Scram Region ensures an early scram and SLMCPR protection.
The Completion Time of 12 flours to cornp1ete the specified actions is reasonahl e, base.ct on operational experience, and based on the importance of restoring an automatic reactor trip for thermal -hydraulic i nstabil Hy events.
BSP is intended ~s a temporary means to protect against thermal-hydra1.,1lic instability events. 1he action should be initiated immediately to docUJnent the situation and prepare the report.
The reporting req~irements of Specification 5.6.B document the corrective actions and schedule to restore the required channels to an OPERABLE status. The Completion Time of 90 days shown in Specification 5.6,8 is adequate to allow time to eva~uate the cause of the j noperabil ity and to determine the appropriate corrective actions and schedule to restore the required channels to OPERABLE status .
                .J.....l If the. Required Action I is not c_omp.Tetetj within the associated Comp) eti on Ti me, then Action J is *required. The Bases for the Manual BSP Regions and associated Completion Time is addressed in the Bases for I.1. The Manual BSP Regions are required ill conjunction whh the BSP Boundary.
LJ The BSP Boundary, as described in Section 7.3 of Reference 22, defines an operating domain where potential instability events can be effectively addressed by the specified BSP manual operator actions. The BSP Boundary is construeted such that a flow reduction ev.ent initiated from this boundary and terminated at th.e core natural circulation line. (NGU would not exceed the Manual BSP Region I stability criterion. Potential instabilities would .develop slowly as a result of the feedwater temperature- transient (Ref. 22).
The Completion Time of 12 hours to complete the specified actions is reasonable, based on operational experience, to reach the specific condition from full power conditioris in an orderly manner and without challenging plant systems .
* PBAPS UN IT 2'                      B 3.3-27a                    Revision N-0. 123
 
RPS Instrumentation B 3.3.1.1
* BASES AffiONS      Ll (continued)
BSP is a temporary means for protection against thermal-hydraulic instability events. An ex-tended period of inoperability without automatic trip capability is not justified. Consequently, the required channels are required to be restored to OPERABLE status within 120 days.
Based on -engineering judgment, the likelihood of an instability event that could not be adequately handled by the use of the BSP Regions (See Action J.1) and the BSP Boundary (See Action J.2) during a 120-day period is negligibly small. The 120-day period is intended to allow for resolution of a variety of equipment problems (e.g.,
design changes, extensive analysis, or other unforeseen circumstances). This action is not intended to be used for operational convenience. Correction of most equipment failures or inoperabilities is expected to normally be accomplished within the completion times allowed for Actions for Conditions A and I.
A  Note is provided to indicate that LCO 3.0.4 is not applic;able. The intent of the note is to allow plant startup whtle operating within tl:le 120-day Completion Time for Required Action J.3. The primary purpose of this exclusion is to allow an orderly completion of design and verifi.cation activities, in the event of a required design change. without undue impact on plant operation .
                  .IW.
If the required channels are not restored to OPERABLE status and the Required Actions of J are not met within the associated Completion Times, then the plant must be placed in an operating condition in whi.ch the LCO does not apply. To achieve this status, the plant must be brought to less than 17.6% RTPwithin 4 hours. The anowed Completion Time is reasonable, based on operating experience, to reach the specified operating power level from full power conditions in
_an, orderly manner and without cha 11 er:iging pl ant systems.
(continued)
* PBAPS UNIT 2                    B 3.3-27b                      Revision No. 143
 
RPS Instrumentation 8 3.3.1.1
~.~--.,-*:~E-:-,-(c~n~i-~:e~-)--------- ---*--- ---- --*---- ----~-
S'URVEI LLANCE    As noted at the beginning of the SRs, the SRs for each RPS REQUIREMENTS      instrumentation Function are located in the SRs column of Table 3.3.1.1-1.
The Surveil Tances a re modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be de1ayed for up to 6 hours, provided the associated Function maintains RPS trip capability. Upon completion of the Surveil 1a nee, or expiration of the 6 hour allowance, the channel must be re t ur ne d t o OPE RA 8 LE stat us or t he a pp l i ca bl e Con d it i on entered and Required Actions taken. This Note is based on the reliabi1ity analysis (Refs. 9, 12 & 13) assumption of the average time required to perform channel Surveillance.
That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RPS will trip when necessary.
SR 3. 3 .1. L 1 Performance of the CHANNEL CHECK ensures that a gross
* failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other ch~nnel~. It is based on the as-sumpt1 on -that i ristrument chan*nel s monitoring the same parameter should read approximately the same val~e.
Significant deviations between instrument channels could be an indicatio,n of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
Agreement criteria are determined by the plant staff biased on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated -with the channels required by the LCO.
SR    3.3.1.1.2 To ensure that the APRMs are accurately indicating the true core ayer-age power, the APRMs are adjusted to the reactor power calculated from a heat balance if the heat balance calculated reactor power exceeds the APRM channel output by more than 2% RTP.
PBAPS UN IT 2                            6 3.3-28                            Revision        149
 
RPS Instrumentation
------~---------- -- , - - -- ~----.--~------- - *-----
B 3.3.1.1 BASES SURVEILLANCE            SR  3.3.1.1,2      (continued)
REQUIREMENTS This Surveillance does not preclude making APRM channel adjustments, if desired, when the. heat balance calculated reactor power is less than the APRM channel output. To provide close agreement between the APRM indicated power and to preserve operating margin, the APRM channels are normally adjusted to w.ithin +/- 2-% of th,e heat balance calculated reactor power. However, this agreement is not required for OPERABILITY when APRM output indicates a higher rea~tor power than the heat balance calculated reactor power.
The Survei 71 ance Frequency is controlled und.er the Survei 11 ance Frequency Control Program *
* PBAPS UNIT 2                                  B 3.3-28a                Revision No. 149
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3,3.1,1,2      (continued)
REQUIREMENTS A restriction to satisfying this SR when < 22. 6% RTP i,s provided that requires the SR to be met only at~ 22.6% RTP because it is difficult to ac:curately maintain APRM indication of core THERMAL POWER consistent with a heat balance when < 22.6% RTP. At low power levels,. a high degree of accuracy is unnecessary because of the large, inherent margin to thermal limits (MCPR, LHGR and APLHGR). At~ 22.6%
RTP, the Surveillance is required to have been satisfactorily performed in accordance with 'SR 3.0.2. A Note is provided which allows an increase in THERMAL POWER above 22.6% if the Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours after reaching or exceeding 22.6% RTP. Twelve hours is based on operating experience and in consideration of providing a reasonable time in whith to complete the SR.
SR 3.3 .1.1.3 (Not Used.)
SR  3. 3 .1. 1. 4
* A CHANNEL FUNffiONAL TEST is performed on eqch required channel to ensure that the entire channel wi'll perform the intended function.. The Surveillance. Frequency is controlled under the Surveillance Frequency Control Program.
SR 3. 3, 1. J., 5 and SR 3, 3. 1. 1. 6 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be made consistent with the ass.umptions of the c:urrent pl ant specific setpoint methodology.
As noted, SR 3.3.1.1.5 is not required to be performed when entering MODE 2 from MODE 1, since testing of the MOOE 2 required WRNM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links.
This allows entry into MODE 2 if the Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours after entering MODE 2 from MODE 1. Twelve hours is based on operating experience and in consideration of providing a reasonab1e time in which to complete the SR.
Th.e Surveil 1ance Frequency is controlled under the Surveillance ~requency Control Program .
* PBAPS UNIT 2                      B 3,3-29 (continued)
Revi.sion No. 143
 
RPS Instrumentation B 3.3.1.1
* BASES SIJRVEILLANCE REaU IREMENTS SR 3:.3.1.l.7 (continued) ( Not Used.)
SR  3 . 3. 1. 1. 8 LPRM gain settings are determined fr0m the local flux pro.files measured hy the Traversing Incore Probe (TIP)
System. This establlshes the re'lative local flux profile for appropriate representative input to th,e. APRM System.
The Surveillance Frequency is controlled under the*
Surveillance Frequency Control Program.
SR 3.3.1.I,9 and SR 3.3.1.1.14 A CHANNEL FUNCTI'ONAL TEST ts performed on e,ach requi'red channel to ensure that the entire ch.anne1 will perform the intended function. Any setpoi nt adjustment s ha 11 be consistent With the assumptions of the current plant specific setpoint methodology. For Function 5, 7, and 8 channels, verificati-0n that the trfp settings are less than or equal to the specifiea Allowable Va1ue during the CHANNEL FUNCTIONAL TEST is not required since the channe1s consist of mechanical switdles and are not su,bject to drift. An exception t0 this are two of the Function 7 level switches which are not mechanical, These Ser.am Discharge Volume (SDV) RPS switches (Fluid Components Inc.) are heat sensitive electronic leve1 detectors w*hiC:h actuate by sensing a difference in temperature. The temp erature 1
detectors are permanently affixed within the scram discharge volume piping conservatively below the level (allowable value a? weasured in gallons) at which an RPS actuation signal Will occur. Since there is no drift involved with the physical location of these switches, verifying the trip settings are less than or equal to the specified allow*able value durtng the CHANNEL FUNCTIONAL TEST is not required.
AdditionalJy, historical calibration d<1ta has indicated that the FCI level switches have not exceeded their Allowable Value when tested.
In addition. Function 5 and 7 instruments are not accessible while th:e unit is operating at power due to high r.adi-cti Qn and the fnstalled indication instrumentation does not provide accurate indication of the trip setting. for the Function 9 channels, veri'fi.cation that the trip sett1ngs are 1ess than
* PBAPS UNIT 2 or equal to the specified Al1owable Value during the CHANNEL B 3.3-30                    Revision No. 114
 
RPS Instrumentation B 3.3.1.l
* BASES SURVEILLANCE REQUIREMENTS SR 3.3,1.1.9 and SR 3.3.1.1,14 (continued)
FUNCTIONAL TEST is not required since the instruments are not accessible while the unit is operating at power due to high radiation and the installed indication instrumentation does not provided accurate i ndi cation of the trip sett1 ng. Waiver of these verif1 c.ati ans for th.e above functi ans is considered acceptable since the magnitude of drift assumed in the setpoint calculat1.on is based on a 24 month calibration interval. The Surveillance Frequency is controlled under the Surveillcince Frequency Control Program.
SR 3.3.1.1.10. SB 3.3,1,1,12. SR 3.3.1,1.15, and SR 3.3.1,1.16 A CHANNEL CALIBRATION i~ a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within _the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations, consistent with the current plant specific setpoint methodology.
As noted for SR 3.3.1.1.10, rad.iation detectors are excluded from CHANNEL CALIBRATION due to ALARA reasons (when the plant is operating, the radiation detectors .are gen.erally in a high radiation area; the steam tunnel). This ,exclusion is acceptable because the radiation detector.s are passive devices, with minimal drift. To complete the radiation CHANNEL CALIBRATION, SR 3.3.1.1.16 requires that the radiation detectors be calibrated in accordance with the Survei 11 ance Frequency Control Program.
SR 3.3.1.1.12 for Function 3.3.1.1-1.2.b is modified by two Notes as identified in Table 3.3.1.1-1. The f1rst Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found. tolerance but conservative with respect to the Allowable Value. Evaluation 0f channel performance wi 11 verify that the channel wi 11 continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the
* PBAPS UNIT 2 p~rformance of these channels will be evaluated under the B 3.3,31                      Revision No. 114
 
RPS Instrumentation B 3.3.1.1
* BASES SURVEILLANCE    SR 3,3.1,1,10. SR 3.3.1,1,12. SR 3.3,1.1.15, REQU IREME"cNTS and SR 3,3.1,1,16 (continued) plant Corrective Action Program, Entry into the Corrective Action Program will ensure required review aDd documentation Of the condition. The second Note requires that the as-left setting for the channel be Within the Leave Alone Zone around the NTSP. wnere a setpoint more conser~ative than the NTSP is used in the pl ant sl!.lrVei 11 a nee procedures (ATSP), the Leave Alone Zone and as-found tolerances, as applicable, will be applied to the survei1lance procedure setpoint. This will ensure that suffitfent mariin to the Safety Limit and/or Analytical Lim-it is maintain"ed. If the as-1 eft channel setting cannot be returned to a setti-ng within the Leave Alone Zone around the NTSP, then the channel shall be declared inoperable. The second Note also requires that NTSP and the methodologies f.o.r calculating t he Le a ve A1on e Zone a nd t h,e as -fo t:1 nd to 1et a nc:e s be i n t he B,ases for the app1icable Technical Specifications.
The Surveillance Frequency is controlled under the Survefl l ante Frequency Control Program.
As noted for SR 3.3.1.1.12, neutron detectors are ex.eluded from CHANNEL CALIBRATION because they are passfve devices, wit h rn t ni ma 1 d r if t , a nd be c a us e of t he dif f i c ult y of simulating a meaningful signal .. Changes in neutron detector sensitivity are compensated for by performing the calorimetric calibration (SR 3.3.l.1.2) and the LPRM calib1;.ation against the TIPs. {SR 3.3.1.1.8)*.
A second note is provided for SR 3.3.1.1.12 that allows the WRNM SR to be performed within 12 hours of entering MODE 2 from MODE 1. Tes,ting of the MODE .2 W'RNM Fun.ctions cannot be performed in MODE 1 without utilizing jumpers, lifted leads or movable links. This Note allows entry into MODE 2 from MODE 1, if the Frequency is not met per SR 3.0,2. Twelve hours is based on operating experience and in consider~tion of providing a reasonable time in which to complete the SR.
A third note is provided for SR 3.3.1.1.12 that includes in the SR the recirculation flow (drive flow) transmitters.
which supply the flow signal to the APRMs. The APRM Simulated Thermal Power-High Function (Function 2.b) and the OPRM llpscale Functfon (Functioti 2.f), botti require a- valid drive flow signal. The APRM Simulated Thermal Power-High
* PEfAPS UNIT 2                            B 3.3-32                            Revision No. 114
 
RPS Instrumentat1on H 3.3.1.1 BASES SURVEILLANCE SR J.3.1.1,10. SR 3,3,1.1,12, SR 3.3,1,1,15.
REQUIREMENTS and SR 3.3,1.1.16 (continued)
Function uses dtive flow to vary the trip setpoint. The OPRM Upscale Function uses drive flow to automatically ena.b1e or bypass the OPRM Upscale trip output to RPS. A CHANNEL CALIBRATION of the APRM drive flow s1gnal requires both calfbratjng the drive flow transmitters and establishing a valid drive flow/ core flow relationship. The crive flow
                /core flow relationship is establi&#xa3;hed once per refuel cycle, while operating at or ~ear rated po~er a~d flow cond1tio~s.
This method of correlating core flow and drive flow is consistent with GE recommendations. Changes throughout the cyc1 e in the drive fl ow I core fl ow relation ship due to the Changing thermal hyd*raulic operating conditions of the core are accounted for in the margins included in the bases or analyses used to establish the setpoints for the APRM Simulated Thermal Powe~-High Function and the OPRM Upscale Function.
The Surveilla~ce f~equency is controlled under the Surveillance Frequercy Control Program .
* SR 3.'3.l.l,11 A C~ANNEL FUNCTIO~Al TEST is performed on each required channel to ensure that the entire channel will perform the intended fur.ction. ror the APRM Functions, this test supplements :be automatic self-test functions that operate continuously in the APRM ara voter c:-:iannels. The scope of the APRM CHANNEL FUNCTIONAL TEST is lim:ted to verification of system ~rfp output hardware. Sof~ware controlled functions are tested on:y incidentally. Automatic intern3l self-test functio1s c~eck the EPROMs in which the software-co11trollec logic is defi11ed. Any changes in the EPROMs wil1 be ~etected by the self>~est function r,esultlng in a trip*
and/or alarm ccnD1tion. The APRM CHANNEL FUNCTIONAL TEST covers the APRM channels (ificludirrg recirculation flow processtng - applicable to Function 2.b and the auto-enable
                ~ortion of Function 2.f orly), the 2-0ut-Of 4 voter ch~nnels, and the interface connections into ,the RPS trip systems from the voter channels. Any setpoint ajjust~ent shall be consistent with the assJmptions of the current plant specific setpoint methodology. The Surveillance Frequenty 1s controlled ~nder the Surveillance Frequency Control Program. (NOTE: H:e actual voting logic of the 2-0u~-Of-4 Voter Funttion is tested as p~rt of SR 3.3.1.1.17 .
* PBAPS UNIT 2                    B 3.3-33                    Revision No. 152
 
RPS Instrumentation B 3.3.1.1
* BASES SURVEILLANCE REQUIREMENTS SR 3.3.l.l.11 (continued)
A  Note is provided for function 2.a that requires this SR to be performed within 12 hours of entering MODE 2 from MODE L Testing of the MODE 2 APRM Function cannot be performed in MODE 1 without utilizing jumpers or lifted leads. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2. _
A  second Note is provided for Function 2.b that clarifies that the CHANNEL FUNffiONAL TEST for Function 2.b includes testing of the recirculation flow processing electronics, excluding the f1ow transmitters.
SR 3.3.1.1.13 This SR ensures that scrams initiated from the Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions will r:iot be inadvertently bypassed when THERMA.I_ PCMER is 2: 26.3% RTP. Thjs involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoin.t. Because main turbine bypass flow can affect this setpoint nonconservatively (THERMAL PO.rJER is derived from turbine fitst stage pressure), the main tu-rbine bypass valves must remain closed during the. calibration at TI-IERMAL PO.tlER
              ~ 26.3% RTP to ensure that the calibration is valid.
If any bypass cha,mel 's setpoin.t is nonconservative (i.e.,
the Functions are bypassed at 2:* 26. 3% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions are considered inoperable. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition1 this SR is met and the channel. is considered OPERABLE.
The Surveillamce Frequency is controlled under the Surveillance Frequency Control Program.
(continued)
* PBAPS UNIT 2                      B 3.3-34                    Revision No. 143
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE  SR    3.3.1.1.17 REQUIREMENTS (cont1nued) The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip log1c for a spec1fic channel. The functional testing of control rods
( LC O 3 . 1. 3 ) , a nd S DV vent a nd d r a i n val ve s ( LC O 3 . 1. 8) ,
overlaps this Surveillance to provide complete testing of the assumed ~afety function.
The Survei 11 ance Frequency is controlled U'nder the Surveillance_Frequency Control Program.
The LOGIC SYSTEM FUNGTUJNAL TEST for APRM Function 2.e simulates APRM and OPRM trip c6nd1ti0ns at the 2-0ut~Qf-4 voter channel inputs to check all combinations of two tripped inputs t9 the 2-0ut-Of-4 logic in the voter channels and APRM related redundant RPS relays.
SR    3.3.l.Ll8 This SR ensures that the individual channel response times are maintained less than or equal to the original design value. The RPS RESPONSE TIME acceptance criterien is included in Reference 11.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR    3,3.1.1,19        Deleted (continued)
PBAPS UNIT 2                          B 3.3-35                            Revision No. 123
 
RPS Instrumentation B 3.3.1.1 BASES  (continued)
REFERENCES        1. UFSAR, Section 7.2.
: 2. UFSAR, Chapter 14.
: 3. NED0-32368, "Nuclear Measurement Analysis and Control Wide Range Neutron Monitoring System LJtensi~g Report for Peach Bottom Atomic Power Station, Units 2 and 3,"
                        *November l99A.
: 4. NEDC-3-3566P, "Safety Analysis Report fo.r* Exe1or;i Peach ottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0.
: 5. UFSAR, Section 14.6.2..
: 6. ITT SAR, Section 14. 5 .4.
: 7. UFSAR:, Section 14.5.1.
: 8. P. Check (NRC) letter to G. Lainas (NRC), "BWR Stram Discharge System Safety Evaluation," December l, 1980 .
* 9.
10.
NED0-30851- P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System,'1 .March 1988.
MDE-87-0485-1, "Technical Specific-ation Improvement Analysis for the Regctor Protection .System for Peach Bottom Atom1 c Power Station Units 2 and 3," Octob*er 1987.
: 11. UPSAR, Section 7.2.3.9.
: 12. NEDC-32410P-A, "Nuclear Measurement Analys9s'and Control Flower Range Neutron MQnitor (NUMAC PRNM)
Retrofit Plus Opti.on III Stability Trip Function,"
October 1995.
: 13. NEDC,32410P Supplement 1, "Nuclear Measurement Analysis and Control Power Range Ne.utron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function, S~pplement Iq, November 1997.
: 14. Deleted
: 15. Del.eted (continued)
* PBAPS UN IT '2                        B 3.3-35a                  Revision No. 123
 
RPS Instrumentation B 3.3.1.l
* BASES REFERENCES (continued) 16.
17 ..
Deleted Deleted
: 18. Deleted
: 19. NED0~24229-1, "Peach Bottom Atomic Power Station Units 2 and 3 Single-Loop Operation," May 1980.
: 20. Setpoint M'ethodo1ogy for Peach Bottom Atomic Power Station and Limerick Generating Station, CC-MA-103--
2001.
: 21. Backup Stability Protection (BSP) for Inoperable Option III Solutions, OG02-0119, July 17, 2002.
: 22. GE Hitachi Nuclear Energy, "GE Hitachi Bo, ling Water Reactor, Detect and Suppress Solution - Confirmation Density," NEDC-33075P-A, Revision 8, November 2013.
: 23. GEH l1etter to NRC, "NEDC-33075P-A, Detect and Suppress Solution - Confirmation 1Density (DSS-CD) Analytical Limit (TAC No. MD0277) , ' October 29, 2008. (ADAMS Accession No. ML083040052) .
* 24.
25.
OOON793.6-RO, "Project Task Report - Exe 1on Generation Company LLC, Peach Bottom Atomic Power Station Unit 2
                      & 3 MELLLA+, Task 10202': Thermal-Hydraulic Stability,"
Ap.ril 2014.
NEDC-33873P, "Safety Analys-is Report for Peach Bottom Atomic Power Station, Units 2 and 3, Thermal Power Optimization," Revision O.
* PBAPS UNIT 2                    B 3.3-35b                  Revision No. 143
 
WRNM Instrumentation B 3.3.1.2
* B 3.3  INSTRUMENTATION B 3.3,1.2  Wide Range Neutron Monitor (WRNM) Instrumentation BASES BACKGROUND        The WRNMs are capable of providing the operator with information r.elative to th.e neutron flux leveJ, at very low flux levels in the core. As such, the WRNM indication is used by the operator to monitor the approach to criticality and determine when criticality is achieved.
The WRNM subsystem of the Neutron Monito~ing System (NMS) consists of eight channels. Each of the WRNM channels can be bypassed, but only one at i3.ny gfven time per RPS trip*
system, by the operation of a bypass switch. Each channel includes one detecto.r that is pertnahently positioned in the core. Each detector assembly consists of a miniature fission* chamber with asBociated cabling, signal conditioning equipmeht, and electr0nics associated with the v~rious WRNM functions. The signal conditioning equipment conve.rts the current pulses from the fission chamber to analog DC currents that correspond to the count rate. Each channel also includes indication, alarm, and control rod blocks.
However, this LCO specifies OPERABILITY requirements only for the monitoring and indication functions of the wRNMs*.
During .refueling, shutdown, anc:I low power operations, the primary indication of neutron 'flux levels is provided by the WRNMs or speciql movable detecto~s connected to the normal WRNM circuits .. The WRNMs provide monitoring of reactivity changes during fuel or controJ, rocl movement and give the control room operator early indication of unexpected subcritical multiplication that could be indicative of an approach to criticality.
APELICABLE        Prevention and mitigation of prompt reactivity excursions SAFETY ANALYSES  during refueling and low power operation is provided by LCO 3. 9 .1, "Refueling Equipment Interlocks"; LCO 3, 1.1, "SHUTDOWN MARGIN (SDM) "; LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"; WRNM P~riod-Short and (continued)
* PBAPS UNIT 2                        B 3.3-36                    Revision No. 24
 
WRNM Instrumentation B 3.3.1.2
* BASES APPLI,CABLE SAFITY ANALYSES
{continued)
Average Power Range Monitor (APRM) Startup High Flux Scram Fund ions; and LCO 3. 3 .. 2.1, "Contra l Rod Block InstrUJnentation."
The WRNMs have no safety function associated with monitoring neutron flux at very low levels and are not assumed to function during any UFSAR design basis accident or transient analysi$ which would occur at very low neutron flux levels.
However, the WRNMs provide the only on-scale monitoring of neutron flux. levels during startup and refuel i ng.
Therefore, they are being retained in Technfcal Specificat.ions.
LCO            During startup in MODE 2, three of the eight WRNM channels are required to be OPERABLE to monitor the reactor flux level and reactor period prior to and during control rod withdrawal , subcri ti cal .multi pl i tat ion and reactor criticality. These three required channels must be located in different core quadrants in order to provide a representation of the overall core response during those periods when reactivity changes are occurring throughout the
* core
* In MODES 3 and 4,, with the reactor shut down, two WRNM channels provide redundant ~n.ftoring of flux levels in-the core.
* I                In HOOE 5, during a spiral offload or reload, a WRNM outside the fueled region Will no longer be required to be OPERABLE, since it is not capable of monitoring neutron flux in the fueled region of the core. lhus, CORE ALTERATIONS are allowed in a quadrant with no OPERABLE WRNH i.n an adjacent quadrant provided the Table 3.3.1.2-1~ footnote (b),
requirement that the bundles bei,ng spiral reloaded or spiral offloaded are all 1'r1 a single fueled region containing at least one OPERABLE WRNH is met. Spiral reloading and offloading encompass reloading or offloading a cell on the edge of a continuous fueled region (the cell can be reloaded or offloaded in any sequence}.
In nonspiral routine ope,rations, two WRNMs are required to be OPERABLE to provide redundant monitoring of reactivity changes in the reactor core. Because of the local nature of reactivity changes during refueling, adequate coverage is provided by requiring one WRNM to be OPERABLE for the connected fuel in the quadrant of the reactor core where
* PBAPS UNIT 2                      B 3.3-37
                                                                              <continued)
Revision No. 24
 
WRNM Instrumentation B 3.3.1.2
* BASES LCO
      * (cont'inued)
CORE ALTERATIONS are being performed. There are two ,WRNMs in each quadrant. Any CORE ALTERATIONS must be perfonned in a region of fuel that is connected to an OPERABLE WRNM to ensure that the reactivity changes are monitored within the fueled region(s) of the quadrant. The other WRNM that is required to be OPERABLE must be in an adjacent quadrant containing fuel.. These requirements ensure that the reactivity of the core will be continuously monitored during CORE ALlERATIONS.
Special movable detectors, according to footnote (c) of Table 3.3.1.2-1, may be used in place of the normal WRNM nuclear detectors. These special detectors must be connected to the normal WRNM circuits ;n- the NHS, such that the applicable neutron flux indication can be generated.
These special detectors provide more fl exi Ml ity in monitoring reactivity changes during fuel loading, since they ,can be positioned anywhere within the core during refueling. They must still meet the location requirements of SR 3.3.1.2.2 and all other required SRs for W~s.
The Table 3.3.1.2-li. footnote (d), requirement provides for conservative spat i a core coverage ..
For a WRNM channel to be considered OPERABLE, it must be providing neutron flux monitoring indication._
I APPLICABILITY    The WRNMs are required to be OPERABLE in HODES 2, 3, 4, and 5 prior to the WRNMs reading 125E-5 % power to provide for neutron monitoring. ln MODE I, the, APRMs prov1 de adequate monitoring of reactivity ,changes in the corei therefore, the WRNMs are not required. In HOOE 2, with WRNMs reading greater than 125E-5 % power, the WRNM Period-Short function provides adequate monitoring and the WRNMs monitori~g indication is not required.
ACTIONS          A, I and B. I In MODE 2r the WRNM channels provide the means of monitQring core reactivity and criticality. With any number of the required WRNMs inoperable, the ability to monitor neutron-flux is degraded. Therefore,, a l i mi ted ti me is a11 owed to restore the inoperable channels to OPERABLE status.
Provided at least one WRNM remains OPERABLE, Required Action .A.I allows 4 hours to restore the required WRNHs to OPERABLE status. This time ts reasonable because there is adequate capability remaining to monitor the core, there is limited ris1< of an event during this time, and there is sufficient time to take. corrective actions to restore the required WRNMs to OPERABLE status. *During this time, control rod withdrawal and power increase is not precluded (continued)
PBAPS UNIT 2                      B 3.3-38                      Revision No. 24
 
WRNM Instrumentation B 3.3 *. 1.2
* BASES ACTIONS    A~l and 8.1 (continued) by this Required Action. Having the ability to monitor the core with at least one WRNM~ proceeding to WRNM indication greate.r than 125E-5 % powe.r, and thereby exiting the Applicabiltty of this LCO, is acceptable for ehsur1ng adequate core monitoring and allow.ing continued operation ..
With three required WRNMs inoperable, RequiFed Action B.l allows no positive changes in reactivity (control rod withdrawal must be immediately suspended) due to inabfl ity to man i tgr the. changes. Required Act ion* A. I still applies and allows 4 hours to restore monitoring capability prior to requiring control rod insertion. This allowance is based on the limited risk of an event during this time, provided that no control rod withdrawals are .allowed, and the desire. to concentrate efforts on repair, rather than to in-mediately shut down, with no WRNMs OPERABLE.
Ll
* In MODE 2j if the required number of WRNMs is not restored to OPERABLE status within the allowed Completion Time, the reactor -sha 11 be pl aced"- in MODE 3. - With a11 contra l -rods fully inserted, the coie is in its least reactive state with the most margin to criticality. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.
D. I and D.2 With one or more required WRNMs inoperable in MODE 3 or 4, the neutron flux monitoring capabi l ity is degraded or nonexistent. The requirement to fully insert all insertable control rods ensures that the reactor will be at its minimum reactivity level while no neutron monitoring capab.ility is available. Pl ac.i ng the reactor mode switch in the shutdown position prevents subsequent control rod withdrawal by maintaining a control rod block. The allowed Completion Time of I hour is sufficient to accomplish the Required Action, and takes into account the low probability of an event requiring the WRNM occurring during this interval.
                                                                      <continued)
* 'PBAPS UNIT 2                                                    Revision No. 24
 
WRNM Instrumentation B 3.3.1.2
* BASES ACTIONS        E.1 and E.2 (continued)
With one or more required WRNMs inoperable in MODE 5, the ability to detect local reactivity changes in the core during refueling is degraded. CORE ALTERATIONS must be imnediately suspended and action must be 111111ediately initiated to fully insert all insertable control rods in core eel ls containing one or more. fuel as.semblies.
Suspending CORE ALTERATIONS prevents the two most probable causes of reactivity changes, fuel loading and control rod withdrawal, from occurring. Inserting all insertable control rods ensures that the reactor iilil'l be at its minimum reactivity given that fuel is present in the core.
Suspension of CORE ALTERATIONS shall not preclude completion of the movement of a component to a safe, conservative position.
Action (once required to be initiated) to insert control rods must continue until all insertable rods in core cells containing one or 1110re fuel assemb1ies a.re inserted.
* SURVEILLANCE REQUIREMENTS As noted at the beginning of the SRs,. the SRs for each WRNN Appl1cabl MODE or other specified conditions are found in t~~ SRs column of Table 3.3.1.2-1.
SR 3.3.1.2~1 and SR 3,3vl.2.3 Performance of the CHANNEL CHECK ensures that a gross failu~e of instrumentatton has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on another channel. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one. of the. channels or something even more serious.
A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.                -
Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit *
* PBAPS UNIT 2                    B 3.3-40 (continued)
Revision No. 24
 
WRNM Instrumentation B 3.3.1.2
* BASES SURVtILLANCE  SR 3 , 3 *1. 2 , 1 and sR  3 . 3 , 1. 2 *3 Ccon t i nue d )
REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
SR  3,3.1.2.2 To provide adequate coverage of potential reactivity changes in the core, one WRNM is required to be OPERABLE for the connected fuel in th.e quadrant wher,e CORE ALTERATIONS are being performed, and the other OPERABLE WRNM must be in an adjacent quadrant containing fuel. Note 1 states that the SR is requir~d to be met Only during CORE ALTERATIONS. It is not required to 'be met at other times in MODE 5 since core reactivity changes are not occurring. This Surveillance consists of a review of plant logs to ensure that WRNMs required to be OPERABLE for given CORE ALTERATIONS are, in fact, OPERABLE. In the event that only one WRNM is required to be OPERABLE, per Table 3.3.1.2-1, footnote (b), only the
: a. portion of this SR is requi~ed. Note 2 clarifies that more than one of the three requirements carr be met by the same OPERABLE WRNM. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR  3,3,1.2.4 This Survei11ance consists of a verification of the WRNM instrument readout to ensure that the WRNM reading is greater than a specified minimum count rate, which ensures that the detectors are indicating count rates indicative of neutron flux levels within the core. The signal-to-noise ratio SQown in Figure 3.3.1.2-1 is the WRNM count rate at which there is a 951 probability that the WRNM signal indicates the presence of neutrons and only a 5% probability that the WRNM signal is the result of noise (Ref. 1). With few fuel assemblies loaded, the WRNMs will not have a high enough count rate to satisfy the SR. Therefore, a]Tbwances are made for loading sufficient "source" material, in the form of irradiated fuel assemblies, to establish the minimum count rate *
* PBAPS UN IT 2                      B 3.3-41                              Revision No. 86
 
WRNM Instrumentation B 3.3.1.2 BASES SURVEILLANCE  SR  3.3.1,2.4  (continued)
REQUIREMENTS To accomplish this, the SR is modified by Note 1 that states
                -that the count rate is not required -to be met on a WRNM that has less than er equal to foui fuel assemblies adjacent to the WRNM and no other fuel assemblies are in the associated core quadrant. Wtth four or less fuel assemblies loaded around each WRNM and no other fuel assemblies in the associated core quadrant, even with a control rod withdrawn, the configuration will not be critical. In addition, Note 2 states that this requirement does ~ot have to be met during spiral unloading. If the core is being unloaded in this manner, the various core configurations encountered will not be critical.
The Surveillance frequency is controlled under the Survei 11 ance Frequency Control Program.
SR  3,3.1.2.5 Performance of a CHANNEL FUNCTIONAL TEST demonstrates the as.sociated channel will function properly. SR 3.3.1.2.5 is reqoired in MODES 2, 3, 4 and 5 and ensures that the channels a-re OPERABLE whi-1 e core react*i vi t-y changes could -be *in - -
progress. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .
* PBAPS UN IT 2                    6 3.3-42                        Revision No. 86
 
WRNM Instrumentation B 3.3.1.2
* BASES SURVEILLANCE REQUIREMENTS SR    3.3.1.2.5    (continued)
Verific~tion of the sig~al to noise ratio also ensures that the detectors are correctly monitoring the neutron flux.
The Note to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability (THERMAL POWER decreased to WRNM reading of 125-E-5 % power or below). The SR must be performed within 12 hours after WRNMs are reading 125E-5 % power or below.
The allowance to enter the Applicability with the Frequency not met is reasonable, based on the limited time of 12 hours allowed after entering the Applicability. Although the Surveillance could be performed while at higher power, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the WRNMs being otherwise verified to be OPERABLE (i.e.; satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances *
* SR    3.3.1.2.6 Performance of a CHANNEL-CALIBRATION verifies the performance of the WRNM detectors and associated circuitry. The Frequency considers the plant conditions required to, perform the test, the ease of performing the tes"t, and the likelihood of a change in the system or compohent status. Note 1 excludes the neutron detectors from the CHANNEl CALIBRATION because they' cannot readily be adj ustec:l. The detectors, a re fission ch a,m be rs t hat a re ct e s i gne ct t o ha ve a rel a t i ve 1y con s t a nt sensitivity over the range a.nd with an accuracy specified for a fixed u.seful Ji fe *
* PBAPS UN IT 2                        B 3.3-43                                  Revision No. 86
 
WRNM Instrumentation B 3.3.l.2
* BASES SURVEILLANCE REQUIREMENTS SR  3.3.1.2.6    (continued)
Note 2 to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability. The SR must be performed in MODE 2 within 12 hours of entering MODE 2 with WRNM.s reading 125E-5 % power or below. The allowance to enter the Applicability with the Frequency not met is reasonable. based on the limited time of 12 hours allowed after entering the Applicability. Although the Surveillance could be performed while at higher power, the plant would not-be expected to maintain steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the WRNMs being otherwise verifiect to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillance.
REFERENCES    1. NRC Safety Evaluation Report for Amendment Numbers 147 and 149 to Facility Operating License Numbers DPR-44 and DPR-56, Peach Bottom Atomic Power Station, Unit Nos. 2 an,d 3, August 28, 1989 .
* PBAPS UN IT 2                    B 3.3-44                  Revision No. 86
 
Control Rod Block Instrumentatfon B 3.3.2.1
* B 3.3  INSTRUHENTATIOfi B 3.3.2.1 BASES Control Rod Block Instrumentation BACKGROUND        Control rods provide the primary means for control of reactivity changes. Control rod block instrumentation includes channel sensors, logic circuitry, switches, and relays that are designed to ensure that specified fuel design limits are not exceeded for postulated transi~nts and accidents. During high power operation~ the rod block monitor (RBM) provides protection for control rod withdrawal error events. During low power operations, control rod blocks from the rod worth minimizer (RWM) enforce specific control rod sequences designed to mitigate the consequences of the control rod drop accident (CRDA). During .shutdown conditions, control rod blocks from the Reactor Mode Switch - Shutdown Position Fun ct ion ensure that a11 contra l rods remain inserted to prevent inadvertent critfcalities.
The purpose of the RBM is to limit control rod withdrawal if localized neutron flux exceeds a predetermined setpoi nt during control rod manipulations. It is assumed to function to block further control rod withdrawal to preclude a HCPR _
Safety Limit (SL) violation. The RBM supplies a trip signal to the Reactor Manual Control System (RMCS) to *appropriately -
inhibit control rod withdrawal during power operation ~bove the low power range setpoint. The RBM has two channels, either of which can i11ttiate a control r*od block when the channel output exceeds the control rod block setpoint. One RBM channel inputs into one RMCS rod block circuit and the other RBM channel inputs into the second RMCS rod block circuit. The RBM channel signal is generated by averaging a set of local power range monitor (LPRM) signals at various cote heights surrounding the control rod .being withdrawn. A signal from one of the four redundant average power range monitor {APRM) channels supplies a reference signal for one of the RBM channels and a sigr:ial from another of the APRM channels supplies the reference signal to the second RBH channel. This reference signal is used to determine which RBM range setpoint {low, intermediate, or high) i.s enabled.
lf the APRM is indicating less than the low power range setpoint, the RBM is automatically bypassed. The RBM is also automatically bypassed if a peripheral control rod*is selected (Ref. 1). A rod block signal is also generated if an RBM inoperable trip occurs, since th1.s could indicate a problem with the RBM channel.
* PBAPS UNIT 2                        B 3.3-45 (continued}
Revision No. 36
 
Control Rod Block Instrumentation B 3.3.2.1
* BASES BACKGROUND (continued)
The inoperab1e trip will occur if, during the nulling .
(nonnal izatfon) sequence, the RBM channel fails to null or too few LPRM inputs are available, if a critical self-test fault has been detected, or the RBM instrument mode switch is moved to any position other than "Operate".
The purpose of the RWM is to control rod patterns during startup and shutdown, such that only specified control rod sequences and relative positions are allowed over.the operating range from all control rods inserted ta 10% RTP.
The sequ~nces effectively limit the potential amount and ra.te of reactivity increase during a CRDA. Prescrtbed control rod sequences are stored in the RWM. which will initiate control rod withdrawal and insert blocks when the actual sequence deviates beyond a11 owances from the stored sequence. The RWM determines the actual sequence based position indication for each control rod. The RWM also uses feedwater flow and steam flow sig1Tals to determine when the reactor power is above the preset power level at which the RWM i's automatically bypassed (Ref. 2). The RWM is a single channel system that provides input into both RMCS rod block circuits .
* With the reactor mode switch in the shutdown position, a control rod withdrawal block ts applied to all control rods to ensure that the shutdown condition is m*aintained. Thies Function prevents inadvertent criticality as the. result of a control rod Withdrawal during MODE .3 or 4, or during MODE 5 when the reactor mode switch is required to be 1n the shutdown position. The reactor mode switch has two channels, each inputting into a separate RMCS rod block circuit. A rod block in either RMCS circuit will provide. a control rod block to all control rods.
APPLICABLE        1. Rod    Block Monitor SAFETY ANALYSES, LCD, and          The RBM is designed to prevent violation of the MCPR APP LI CAB IL ITV SL and the cladding 1% plastic strain fuel design limit that may res.ult from a .single control rod withdrawal error (RWE) event. The, a,nalytical methods and assumptions used 1n evaluating the RWE event are summarized in Reference 1. A
                                                                      <continued}
* PBAPS UNIT 2                        B 3.3-46                    Revision No. 36
 
Control Rod Block Instrumentation B 3.3.2,1
* BASES
  .AEPLICABLE SAFETY ANALYSES, LCO, and 1,  Rod Block Monitor    (continued) statistical analysis of RWE events was performed to APPLICABILITY      determine the RBM response for both channels for each event.
From these responses, tne fuel therm.al perf"ormartce as a function of RBM Allowable Value was determined.      The Allowable Values are chosen as a :function of power level.
The Allowable Val1,1es are sl?ecified in the CORE OPERATING L!MITS REPORT (COLR) . Based on t:h:e specified }Ulowab1e Values, ~perating limits are established.
The RBM Function .satisfies Criterion 3 of the NRG Policy Statement.
Two channels of the RBM are required to be OPERABLE, with their setpoints within the appropriate Allowable Values to ensure that no single instrument failure can preclude a rod block froin this .Function. The actual setpoints are calibrated consistent with applicable setpoint methodology.
Trip setpoints are specified in the setpoint calculations.
The trip setpoints are selected to ensure that the setpoints do not exceed the Allowable Values between successive CHANNEL CID,IBRA'I'IONS. Operation with a trip setting less c:Onse_rvative than the trip setpoint, but within its.
Allowable Value, is acceptable.      Trip setpoipts a:i;e those predetennihed values of output at which an action should take place. The setpoiats are coIIII?ared to th~ actual process parameter (e.g., reactor power), and when the measure'd output value of the process parameter exceeds the se.tpoint, the ass.ociated device (e.g., trip unit) changes state.. The analytic or design limits are derived from the limiting valu.es of the process parameters o};)tairted from the safety analysis or other appropriate doc11II1ehts. The
                    .Allowable Values are derived from the analytic or design limits, corrected for calibration, process, and instrument errors. The trip setpoints are determined from analytical or design liroi ts, corrected for calibration, process,. and instrument errors, as well as, instrument drift.        In selected cases, the Allowable Values and trip se.tpoints are qetertnined by engineering judgement or historically accepted practice relative to the ihtended function of the channel.
The trtp aetpoints detennined in this manner provide adequate protection by assuring instrument and process uncertainties expected for the environments during the operating time o:f the channels are accounted .for.
(continued)
PBAPS UNIT 2                          B 3.3--fl                    Revision No. 0
 
Control Rod Block Instrumentatton B 3.3 . . 2.1
* BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY
: 1. Rod BJ ock Mon Hot  (continued)
The RBM is assumed to mitigate the consequences of an RWE event when operating~ 28.4% RTP. Below this power level, the consequences of an RWE event will not exceed the MCPR SL and, therefore, the RBM is not required to be OPERABLE.
Analyses (Ref. 1) have shown that with an int ital MCPR greater than or equal to the limit specified in the COLR, no RWE event will result fn exceeding the MCPR SL. Therefore, under these condit1ons, the RBM is also not required to be OPERABLE.
2,  Rod worth Minimizer The RWM enforces the analyzed rod position sequence to ensure that the initial conditions of the CRDA analysis are not violated. The analytical methods and assumptions used in evaluating the CRDA are summarized in References 3, 4, 5, and 11. The analyzed rod position sequence requires that control rods be moved in groups, with al 1 control rods assigned to a specific group required to be within specified banked positions. Requirements that the control rod sequence is in compliance with the analyzed rod position sequence are specified in LCO 3.1.6, "Rod Pattern Control."
* When performing a shutdown of the plant, an optional control rod sequence (Ref. 11) may be used if the coupling of each withdrawn control rod has been coflfirmed. The rods may be inserted without the need to stop at intermediate positions, When using the Reference 11 control rod insertion sequence for shutdown, the RWM may be reprogrammed to enforce the requirement~ of the improved control rod insertion process, or may be bypassed and the improved control rod shutdown sequence implemented under the controls in Condition D.
The RWM Function satisfies Criterion 3 of the NRC Policy
                  -Statement.
Since the RWM is a hardwired ~ystem designed to act as a backup to operator control of the rod sequences, only one channel of the RWM is available and required to be OPERABLE (Ref. 6). Special circumstances provfded for in the Required Action of LCO 3.1.3, "Control Rod OPERABILITY," and LCO 3.1.6 may necessitate bypassing the RWM to allow continued operation with inoperable control rods, or to allow correction of a control rod pattern not in compliance with the analyzed rod pos1tion sequence. The RWM may be bypassed as required by these conditionsj but then it must be considered inoperable and the Required Actions of this LCO followed.
Cc9ntinued)
PBAPS UNIT 2                        B 3.3-48                    Revision No. 143
 
Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE          2. Rod Worth Minimizer  (continued)
SAFETY AN.ALYS ES I LCO, ahd            Compliance with the analyzed rod position s,equence, ,and APPLICABILITY      therefore OPERABILITY of the RWM, is required in MODES 1 and 2 when THERMAL POWER is < 10% RTP. When THERMAL POWER is> 10% RTP, there is no possible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Refs, 4 and 6).
In MODES 3 and 4, all control rods are required to be inserted into the core; therefore, a CRDA cannot occur. In MODE 5, since only a single control rod can be withdrawn from a core cell containing fuel assemblies, adequate SOM ensures that the consequences Gf a CRDA are acceptable, since the reactor Will be subcritical.
: 3. Reactor Mode Switch-Shutdown Position During MODES 3 and 4, and during MODE 5 when the reactor mode switch is required to be in the shutdown positi.on, the core is assumed to be subcritical; therefore, no positive
* reactivity insertion events are analyzed. The Reactor Mode SwHch-Shutdown Position control rod withdrawal block ensures that t~e reactor remains subcritical by blocking control rod withdrawal, thereby preserving the assumptions of the safety ana1ysis.
The Reactor Mode Switch-Shutdown Position Function satisfies Criterion 3 of the NRC Policy Statement.
Two channels are required to be GPERABLE to ensure that no single channel failure will preclude a rod block when required. There is no Allowable Value for th1s Function since the channels are mechanically actuated based solely on reactor mode switch position.
During shutdown conditions (MODE 3, 4, or 5), no positive reactivity insertion events are analyzed because assumptions are that control rod withdrawal blocks are provided to prevent criticality. Therefore, when the reactor mode switch is in the shutdown position, the control rod withdrawal block is required to be OPERABLE. During MODE 5 with the reactor mode switch in the refue1ing position. the refue1 position on.e-rod-out interlock (LCO 3.9.2, "Refuel Position One-Rod-Out Interlock") provides the required control rod withdrawal blocks .
* PBAPS UN IT 2                        B 3.3-49 (continu.ed)
Revision No. 63
 
Control Rod Block Instrumentation B 3.3.2.1
* BASES  (continued)
ACTIONS            A.J.
With one RBM channel inoperable, the remaini.ng OPERABLE chclnhel is adequate, to perform the control rod block function; however, overall reliability is reduced because a si,ngle failure in the reQlaining OPERABLE channel can result in no control rod block capability for the RBM. For this reason, Required Action A.I requires restoration of the inoperable channel to OPERABLE status. The Compl1!tion Time of 24 hours is based on the low probability of an event occurring cotnci'dent with a failure in the remaining OPERABLE channel.
JW.
If Required Action A.1 is not met and the associated Completion Time has expired, the inoperable channel must be placed in trip withtn I-hour. If both RBM channels are inoperable, the RBM ts not capable of perfortning its -
intended function; thus, one channel must also be placed 1n trip. This initiates a control rod withdrawal block,
* thereby ensuring that the RSM function is met
* The 1 hour Completion lime is intended to allow the operato.r t,me to evaluat1f and-repair any-discovered-ino-peraoi1iti~s --
and is acceptable because 1t-111inimizes rfsk while a1lowing time for restoration or tripping of inoperable channels.
C.I, c.2.1.1, t.2.1.2, and C.2.2 With the RWM inoperable durin_g a reactor startup, the operator is st i 11 capable af enforcing the prescribed control rod sequence. However, the overall reliability is reduced because a .single oper:ator error can result 1n violating the ,control rod sequenc--e. Therefore, control rod.
movement must be immediately suspended except by scram.
Alternatively, startup may continue if at least 12 control rods have already been withdrawn, or a reactor startup with an inoperable RWM was not performed in the last 12 months.
These requirements minimize the number of reactor startups initiated with the RWM inoperable. Required Actions C.2.1.1 and C.2.1.2 require verification of these conditions by review of plant logs and' control room indications. Once Required Action C,2.1.1 or C.2.1.2 is satisfactorily
                                                                          <cgnttnuedl PBAPS UN,IT 2                          B 3.3-50                      Revision No. 0
 
Control Rod ,&#xa3;31 ock Instrumentation
                                                                          .B 3 .3. 2 .1
* BASES ACTIONS      C.l, C,2,1,1,  C,2.1,2, and C,2.2 (continued) completed, control rod withdrawal may proceed, in accordance with the restrictions imposed by Required Action C.2.* 2.
Required Action C.2.2 allows for the RWM Function to be performed 111anually and requires~ double check of compliance_
with the prescribed rod sequence by a second licensed ope.rator (Reactor Operator or Senior Reactor Operator) or other qualified IIE!lllber of the technical staff. The RWM may be bypassed Under these conditions to allow continued
* operations. In addition, Re qui red Actions of LCO 3 *I. 3 and LCO 3.1.6 may require bypassing the RWM, during which time the RWM .must be considered inoperable wi.th Cond,tion C entered and its Required Actions taken *
              .lhl Wtth the RWM inoperable during a reactor shutdown, the operator is still capable of enforcing the prescribed control rod sequence. Required Action D.l allows for the RWM Function to be performed manually and requires a double
* check of compliance with the prescribed rod sequence by a second licensed operator (Reactor Operator or Senior Reactor Op~rator) or other qualified member of the technical staff ..
The RWM may be bypassed under these conditions to allow the reactor shutdown to continue~
E. I and E.2 With one Reactor Mode Switch-Shutdown Position control rod withdrawal block channel inoperable, the remaining OPERABLE channel is adequate to perfonn the control rod withdrawal block function. However, since the Required. Actions are consistent with the normal action of an OPERABLE Reactor Mode Switch-Shutdown Position Function {i.e., maintaining all control rods inserted), there is no distinction between having one or two channels inoperable~
In both cases (one or both channels inoperable), suspending all control rod withdrawal and initiating action to fully insert a1 l i nsertab1e control rods in core ce 11 s containing one or fDQre fuel assemblies will ensure that the core is
* subcritical with adequate SOM ensured by LCO 3. 1.1. Control rods in core cells containing no fuel assemblies do not (continued)
PBAPS UNIT 2                    8 3.3-51                          Revision No. 0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES ACTIONS      E,l and E,2      (continued) affect the reactivity of the core and are therefore not required to be inserted. Action must continue until all in~ertable control rods in core cells containing one or more fuel assemblies are fully inserted.
SURVEILLANCE  As noted at the beginning of the SRs, the SRs for each REQUIREMENTS  C0ntrol Rod Block instrumentation Function are found in the SRs column of Table j.3.2.1-1.
The Surveillances are modified by a Note to indicate that when an RBM channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintatns control rod block capability. *upon completion of the Surveilla~ce, or expiration of the 6 hour allowance, the charrnel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.
This Note is based on the reliability ahalysfs (Refs. 8, 9,
*              & 10) assumptions of the average time required to perform channel surveillances. That analysis demonstrated that the 6 h_o~_r testi_n_g allowance does not signiftcantly reduce the probability that a control rod block will be initiated when r:rncessary.
SR  3,3.2,1.1 A CHANNEL FUNCTIONAL TEST is performed for each RBM channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Survei 11 ance Frequency Control Program .
* PBAPS UN IT 2                      8 3.3-52                    Revision No. 86 I,
 
Control Rod Block Instrumentation B 3.3.2.1
* BASES SURVEILLANCE      SR 3,3.2,1,2 and SR 3,3,2,1.3 REQUIREMENTS
( cont i rrned) A CHANNEL FUNCTIONAL TEST is performed for the RWM to ensure that the entire system will perform the intended function.
The CHANNEL FUNCTIONAL TEST for the RWM is performed by withdrawing a control rod not in compliance with the prescribed sequence and verifying a control rod block occurs. It is permissible to simulate the withdrawn control rod condition into the RWM in order to verify a control rod block occurs. SR 3.3.2.1.2 is performed during a startup and SR 3.3.2.1.3 is performed during a shutdown (or power reduction to s 10% RTP). As noted in the SRs, SR 3.3.2.1.2 is hot required to be performed Lmti l 1 hour after any control rod is withdrawn at s 10% RTP in MODE 2. As noted, SR 3.3.2.1.3 is not required to be performed until 1 hour after THERMAL POWER is s 10% RTP in MODE 1. This allows entry at s 10% RTP in MOD&#xa3; 2 for SR 3.3.2.1.2 and entry into MOD&#xa3; 1 when THERMAL POWER is s 10% RTP for SR 3.3.2.1.3 to perform the required Surveillance if the Frequency is not met per SR 3.0.2. The 1 hour allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR 3.3,2.1.4 The RBM setpoints are automatically varied as a function of power. Three Allowable Values are specified in the COLR, each within a specific power range. The power at which the control rod block Allowable Values automatically change are based on the APRM signal 1 s input to each RBM channel. Below the minimt:Jm power setpoint. the RBM is automatically bypassed. These power Al1owable Values must be verified t:Jsing a simulated or actual signal periodically to be less than or equa1 to the specified values. If any power range*
setpoint is nonconservative, then the affected RBM channel is considered inoperable. Alternatively, the power range
* PBAPS UNIT 2                        B 3.3-53                    Revision No. 86
 
Control Rod Bl oc.k Instrume'ntati on B 3.3.2.1
* BASES SURVEILLANCE REQUIREMl:NTS SR 3.3.2.1.4 (continued) channel can be placed in the Conservative condition (i.e.,
enabling the proper RBM setpoint). If placed in this condition, the SR is met and the RBM channel is not considered inoperable. As noted, neutron detectors are excluded from the Surveillance because they are passive devices, with.minimal drift, and because of the difficulty of simulating a meaningful signa1.
Neutron detectors are adequately tested in SR 3.3.1.1.2. and SR 3.3.1.1.8. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR 3,3.2.1.5 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEi.. CAUBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
As noted, neutron detectors are excluded from the CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Neutron detectors are adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.8. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .
* PBAPS UN IT 2                  B 3,3-54                    Revision No. 86
 
Control Rod Block Instrumentation B 3.3.2.1
* BASES SURVEILLANCE REQUIREMENTS SR    3.3.2,1.6 (continu,ed) The RWM is automatically bypassed when power is above a specifie.d value. This automatic action can itself be bypassed to allow for control rod sequence enforcement up to 100% RTP. The power level is determined from feedwater flow and steam flow signals. The automatic bypass setpo1nt must be verified periodically to be> 10% RTP. If the RWM low power set point is nrmconservat i ve, then the RWM is considered inoperable. Alternately, the <low power setpoint channel can
                .be p1a ce d i n the co ns e r va t i ve con dit i on ( non byp as s ) . I f placed in the nonbypassed condition, the SR is met and the RWM is not considered inoperable. The Surveillance Frequency is controlled under the Surveillance Freq~ency Control Program.
SR    3.3,2.1.7 A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode Swttch-Shutdown Position Function to ensure that the entire channel will perform the int~nded function. The CHANNEL FUNCTIONAL TEST for the Reactor Mode Switch-Shutdown Position Function is performe.d by ac:ttempting to withdraw any control rod with the reactor mode switch-in the shutdown position and verifying a control rod block occurs.
As noted 'In the SR, the Survei 11 ance is rwt required to be perfcirmed until 1 hour after the reactor mode switch is in the shutdown position, since testing of this interlock with the reactor mode switch in any other position cannot be performed without using jumpers, lifted leads, or movable links. This allows entry into MODES 3 and 4 if the Erequenty is not met per SR 3.0.2. The 1 hour allowance is based on operating experience and in consideratiol'il of providing a reasonable time in which to complete the SR .
* PBAPS UN IT 2                      B 3.3-55                                Revision No. 86
 
Control Rod Block Instrumentation 13 3.3.2.1 BASES SURVEILLANCE  SR 3 . 3 . 2 . 1. 7 ( con t i n ued )
REQUIREMENTS The Surveillance Frequency is controlled under the Survei 11 anoe Freque,ncy Control Program.
SR  3.3.2.1.8 The RWM will only enfoPce the proper control rod sequence if the rod sequence is properly input into the RWM computer.
This SR ensures that the proper sequence is loaded 1nto the RWM so that tt can ~erform its intended function. The Surveillance is performed once prior to declaring RWM OPERABLE following loading of sequence into RWM, since this is when rod sequence input errors are possible.
REFERENCES    1. NED C-3216 2 - P,    11 Max i mum Extend ed Lo ad Li ne Li mi t and ARTS Improvement Pf'ogram Analysis for Peach Bottom Atomic Power Station, Units 2 and 3, Revision 1, 11 February 1993 .
* 2.
3.
4.
UFSAR, Sections 7.10.3.4.8 and 7,16.3 ..
NEDE"24011-P-A, Ge.neral Electric: Standard Application 11 for Reactor Fuel, la test approved revision.
11 "Modiftcations to the *Requirements for Control Rod Drop Accident Mftigating Systems," BWR Owners' Group, July 1986.
: 5. NED0-21231, "Banked Position Withdrawal Sequence,"
January 1977.              *
: 6. NRC SER, ".Acceptance of Referencing of Licensing Topical Report NEDE-24011-P-A,'' "General Elec:tric Standard Application for Reactot Fuel, Revision 8, Amendment 17," December 27, 1987 .
* PBAPS UN IT 2                        B 3.3-56                            Revision No. 86
 
Control Rod Block Instrumentation B 3,3.2.1
* BASES REFERENCES (continued)
: 7. NEDC-30851-P-A, "Technical Specification Improvement Analys.i,.s for BWR Control Rod Block Instrumentation,"
October 1988.
: 8. GENE-770-06-1, "Addendum to Bases fo:t:' changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," february 1991,
: 9. NEDC-32410!?-A, \'Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM)
Ret;c,ofit Plus Option III Stability Trip Function",
March 1995.
: 10. NEDC-32410P Supplement 1, "Nuclear Measurement Analysis ahd Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option IIT Stability Trip Function, Supplement 1", November 1997.
: 11. NED0-33091-A, "Improved EPWS Control Rod Insertion Process," Rev~s~on 2, July 2004
* PB.APS UNIT 2                    B 3.3-57                    Revision No. 61
 
Feedwater and Main Turbine H1gh Water Level T.r1p Instrumentation B 3.3.2.2 B 3.3  IN STRUM ENT ATI ON B 3.3.2.2  Feedwater and M~in T~rbine High Water Level Trip Instrumentation BASES BACKGROUND          The feedwater and main turbine high water level trip instrumentation is designed to detect~ potential failure of the ~eedwater Level Control System that causes excessive feedwater flow.
With excessive feedwater flow, the water level in the re.actor vessel rises toward the high water level setpoint, causing the trip of the three feedwater pump turbines and the main turbine.
DigHal Feedwater Control System (DFCS) high water level signals are provided by six level sensors, three narrow range and th~ee wide range. The three narrow range level transmitters are used to satisfy the TS re.qu1rement. The three level sensors sense the difference between tne pressure due to a. constant column of water ( reference 1eg) and the pressure due to the actual water level in the reactor vessel (variable leg). The three level signals are input ,nto two independent and redundant digital control systems. within the DFCS. Each control system includes redundant controllers capable of perform1 ng the mi gh 1evel trip function. All three level signals are used by the digital control systems to produce a vaHdated level signal for use for the high level trip function.
Each independent digital control system bas two redundant digital outputs (ch.annels) to provide l"edundant signals to an associated trip system. Each independent digital control system processes input signals and compares them to pre-established setpoints. When the setpoint is exceeded, the two digital outputs actuate two contacts arrapged in parallel so that either digital output can trip the associated trip system. The tripping of both digital trip systems w11 l 1niti ate a trip of tbe feedwater pump turbines and the main turbine.
A trip of the feedwater pump turbines limits further increase in reactor vessel water 1evel .by 11m1ting further addition of feedwater to the reactor vessel. A trip of the main turbine and closure of the stop valves protects the turbine from damage due to water entering the turbine.
(continued)
* PBAPS UNIT 2                            B 3.3-58                    Revision No. 146
 
Feedwater and Main Turbine High Water level Trip Instrumentation B 3.3.2.2
* BASES  (continued)
APPLICABLE SAFETY ANALYSES The feedwater and main turbine high water level trip instrumentation is assumed to be capable. of providir:ig a turbine trip in the design basis transient analysh for a feedwater controller failure, maximum demand event (Ref. 1).
The high Water level trip indirectly initiates a reactor scram from the main turbine trip (above 26.3% RTP) and trips the feedwater pumps, thereby terminating the event.
The reactor scram mitigates the reduction in MCPR.
Feedwater and main turbine high water level trip instrumentation .satisfies Criterion 3 of the NRC Policy Statement.
LCO                The LCO requires two DFCS channels per trip system of high water level trip instrumentation to be OPERABLE to ensure the feedwater pump turbines and main turbir:ie will trip on a valid reactor vesse1 high water level signal. Two DFCS channe1s (one per trip system) are needed to provide trip signals in order for the feedwater and main turbine trips to occur.
Two level signals are also required to ensure a single sensor failure will not prevent the trips of the feedwater pump turbines and main turbine when reactor vessel water level is at the high water level reference point.
E'ach channel must have its setpoint set within the specified Allowable Value of SR 3.3.i.2.3. The Allowable Value is set to ensure that the thermal limits are not exceeded during the event. The actual setpoint is calibrated to be consistent with the applicable setpoint methodology assumpti ans. Trip setpoi nts are specified in the setpoi nt calculations. The trip setpoints are selected to ensure that the setpo.i nts do not exceed the A11 owabl e Value. between successive OiANNEL CALIBRATIONS. Operation with a trip setting less conservative than the tri'p set point, but within its Allowable Value, is acceptable.
Trip setpoililts are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.,g., trip unit) changes state.. The analytic or design limits are derived from the limiting values of the process parameters obtained from the safety analysis or (continued)
* PBAPS UNIT 2                          B 3.3-59                    Revision No. 141
 
Feedwater a11d Main Turbine High Water Level Trip Instrumentation B 3.3.2.2
* BASES LCO (continued) other appropriate documents. The Allowable Values are
                <Jerived from the analytic or design limits, corrected for calibration, process, and i.nstrument errors. A channel is inoperable if its actual trip setting is not within its required Allowable Value. The trip setpoints are determined from analytical or design limits, corrected for calibratfon, process and instrument errors, as well as, instrument drift:.
The trip .setpoints determined in this manner provide adequate protection by assuring instrument and process uncertainties expected for the environment during the operating time fur the associated channels are accounted for.
APPLICABILITY  The feedwater .and main turbine high water level trip instrumentation is required to be OPERABLE at~ 22.6% RTP to ensure that the fuel cladding integrity Safety Limit and the cladding 1% plastic strain 1imit are not violated during the feedwater ,controller failure, maximum demand event. 'As discussed in the Bases for LCO 3., 2. 3, "LINEAR HEAT GENERATION RATE (LHGR)," and LCO 3. 2. 2, "MINIMUM CRITICAL POWER RATIO (MCPR)," sufficient margin to the.se limits exists be]ow 22.6% RTP; therefore, these requirements are only necessary when operating at or above this power level .
ACTIONS        A Note has been provided to modify the ACTlONS related to feedwater and main t~rbine .high water level trip instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Conditicm. Section 1,3 also specifies that Required Actions of the Conditfon continue to apply for each additional failure., with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable feeclwater and main turbine high water level trip instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable feedwater and main t1,.1rbine high water level trip instrumentation channel.
(continued)
PBAPS UNIT 2                        B 3.3-60                      Revision No. 143
 
Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.,2.2
* BASES ACTIONS (continued)
AJ.
With one or 110re feedwater and main turbine h.igh water level trip channels inoperable, but with feedwater and main turbine high water level trip capability ma,intained (refer to Required Action B.1 Bases), the remaining OPERABLE channels can provide the required trip signal. However, overall instr1.111entat1on reliability ts reduced because a singla active instrument failure in one of the remaining channels may result in the instrumentation not being able to perform tts intended function. Therefore, continued operation 'is only allowed for a limited time with one or more channels inope,rable. If the inoperable channels cannot be restored to OPERABLE status within the Comp 1 et ion Ti me,,
the channels must be placed in the tripped condition per Required Action A.I. Placing the inoperable channe'l in trip would conservatively compensate for the inope~ability, restore capability to acc0111110date a single active instrument failure, and allow operation to continue with no further restrictions. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result i.n the feedwater and main turbine trip), Condition C must be entered and its Required Action taken.
The Completion Time of 72 hours -is based on the low
                    ,probability of the event occurring coincident with a single failure in a remaining OPERABLE channel *
                  . Required Action 8.1 is intended to ensure that appropriate actions are taken if 111ultiple, inoperable, untripped channels result in the High Water Level Function of DFCS not maintaining feedwater and 111ain turbine trip capabilfty. In*
this condition, the feedwater and main turbine high water level trip instrumentation cannot ,perform its design function., Therefore, continued operation is only permitted for a 2 hour period, during which feedwater and main turbine high water level trip capability must be restored., The trip capability is considered maintained when sufficient channe'l s are OPERABLE or in trip such that the feedwater and main turbine high water level trip 1ogic will generate a trip
{continued}
* PBAPS UNIT. 2                        B 3.3-61                      Revision No. O
 
Feedwater and Main Turbine High Water Level Trip Instrumer:itation B 3.3.2.2 BASES ACTIONS          IL.l  (continued) si~nal on a valid signal. This requires one channel per trip system to be OPERABLE or in trip. If the required channels cannot be restored to OPERABLE status or placed in trip, Condition C m1:1st be entered and its Required Action taken .
The 2 hour Completion Time is sufficient for the operator to take corrective action, and takes into accol!nt the likelihood of an event requiring actuation of feedwater and main turbine high water level trip instrumentation occurring during this period. It is also consistent with the 2 !:lour Completion Time provided in LCO l.2.2 for Required Action A.1, since this instrumentation's purpose is to preclude a MCPR violation.
Cl and C.2 With any Required Action and associat.ed Completion Time not met, the pl ant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to< 22.6% RTP within 4 hou,rs. Alternatively, the affected feedwater pump(s) and affected main turbine valve(s) may be removed from service since this performs the intended function of the              _
instrumentation. As discussed in the Applicability section of the Bases, operation below 22.6% RTP results in sufficient margin to the required limits, and the feedwater and main turbine high water level trip instrumentation is not required to protect fuel integrity during the feedwater controller failure, maximum demand event. The allowed Completion Time of 4 hours is based on operating experience to reduce THERMAL POWER to< 22.6% RTP from full power conditions in an orderly manner and without challenging plant systems.
Required Action C.l is modified by a Note which states that the Required Action is only applicable if the inoperable channel is the result of an inope,rable feedwater pump turbine or main turbine stop valve. The Note clarifies the situations under which the assodated Required Action would be the appropriate Required Action.
SURVEILLANCE      The Surveillances are modified by a Note to indicate that REQUIREMENTS      when a chanr:1el is placed in an inoperable status *solely for performance of required Survei Tl ances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains feedwa:ter and main turbine_high w.ater level trip capability. Upon completion of the Surveillance, or
* expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is-based on the reliability analysis (Ref. 2) assumption of the average time required to perform Ccontinued)
PBAPS UNIT 2                        B 3.3-62                  Revi s*i on No. 143
 
Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2
* BASES SURVEILLANCE REQUIREMENTS (continued) channel S,urveil1ance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the feedwater pump turbines and main turbine will trip when necessary.
SR 3. 3 . 2 . 2 . 1 Performance of the CHANNEL CHECK once every -24 hours ensures th~t a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. The CHANNEL CHECK may be performed by comparing indication or by verifying the absence of the DFCS "TROUBLE" alarm in the control room. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations betwe.en instrument channels col!lld be an indication of excessive 1nstrument drift in one of the channels~ or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly
* between each CHANNEL CALIBRATION .
Agreement_criteria are tjetermin~d by the_plant staff ~ased on a combination of the channel instrument uncertainties, including indication and readability. I.fa channel is outside the criter~ a, it may be an. i ndi c.ati on that the instrument has drifted outside its limits.
Yhe Surveillance Frequency is controlled unde.r the Surveillance Frequeficy Control Program. The CHANNEL CHECK supplements less formal, b~t more frequent, checks of channel status during normal operational use of th.e displays.
associated wit~ the channels required by the LCO.
SR  3.3.2.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel wi.l l perform the intended function. Any setpoint adjustment shall be consistent ~ith the assumptions of the current plant specific setpoint methodology, The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .
* PBAPS UN IT 2                        B 3.3~63                      Revision No. 86
 
Feedwater and Main Turbine High Water Level Trip Instrumentation B 3. 3. 2. 2.
* BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.2.2,3 CHANNEL CALI~ON is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the mecessary range and accuracy. CHANNEL CALIBRATION leaves the channel
                    .adjusted to account for instrument drifts between successive calibrations, consistent with the assumptions of the current p1ant specific setpoi nt methodology, The Surveilliance Frequency is controlled under the Surveillance Frequency Control_Program.
SR 3.3.2.2.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The .system functional test of the feedwater and main turbine stop valves is included as part of this Surveillance and overlaps the LOGIC SYSTEM FUNCTIONAL TEST to provide complete testing of tl:!e assumed safety function.
Therefore. if a stop valve is incapable of operating, the associated instrumentation channels would be inoperable.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
REFERENCES          1. UFSAR, Section 14.5.2.2.
: 2. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-Of-Service. Times for Selected Instrumentation Technical Specifications,"
February 1991.
: 3. NEDC-33873P, "Safety Analysis Report for Peach Bottom Atomic Power Station, Unjts 2 and 3, Tl:!ermal Power Optimization," Revision O.
* PBAPS UNIT 2.                        B 3.3-64                    Revision No. 143
 
PAM' Instrumentation B 3.3.3.1
* B 3 .3  INSTRUMENTATION B 3.3.3.1    Post Accident Monitoring (PAM) Instrumentation BASES BACKGROUND        The primary purpose of the PAM instrumentation is to display plant variables that provide. i.nfortnation required by the control room operators during accident situations. This information provides the necessary support for the operator to take the manual actions for which no automatic control is
                    .provided and th'at are required fat safety systems to accomplish their safety functions for Design Basis Events.
The instruments that 110nitor these variables are designated as Type A, Category I, and non-Type A, Category I, in accordance with Regulatory Gui~e 1.97 (Ref. I).
The OPERABILITY of the accidtmt monitoring instrumentation ensures that there is sufftcient infonnation available on selected plant parameters to JDOnitor and assess plant status and beh~vior following an accident. This capabil Uy is consistent with the reco11111endations of Reference 1 .
* APPLICABLE
  ~~FETY _ANALYSE,S_
The PAM instrumentation LCO ensures the OPERABILITY of Regulatory Guide 1.97., Type A variables so that the. control room oper~ing staff can:*-
Perfonn the diagnosis spec.ified 1n the Emergency Operating Procedures (EOPs). These variables are t""estri.cted to preplanned acti ans for the prima,ry success path of Design Basis Accidents (DBAs), {e.g. ,.
loss of coolant accident (LOCA)), and
* Take the specified, preplanned, manually controlled actions for which no automatic control is provided, which are required for safety systems to accomplish their safety function.
The PAM instrUJilentat1on LCO al so ensu,res OPERABILITY of Category I, non-Type' A, variables. so that the control room operating staff can:
* Determine whether systems illlJ)ortant to safety are perfoming thei.r intended functions;
{continued}
* PBAPS UNIT 2                            B 3.3-.65                      Revision No. o
 
PAM Instrumentation B 3.3.3.1
* BASES APPLICABLE SAFITY ANALYSES
{continued)
                  **    Determine the potential for causing a gross breach of the barriers to radioactivity release;
* Deterflline whether a gross breach of a barrier has occurred-; and
* Initiate action necessary to protect the public and for an esti*mate of the magnitude of any impending threat *.
The plant spec.ific Regu,latory Guide 1.97 Analysis (Refs. 2, 3, and 4} documents the process that identified Type A and Category l, non-Type A, variables.
Accident 1110nitori,ng instrumentation that satisfies the definition of Type A in Regulatory Guide l.97 meets Criterton 3 of the NRC Policy Statement. Category I, non-Type A, instrumentation is retained in Technical Specifications (TS) .because they are intended to assist ope.rators in minimizing the consequences of accidents.
Therefore, these Category I variables are important for reducing public risk.
LCO            LCO 3.3.3.1 requi*res two. OPERABLE channels for .all but one Function to ensure that no single failure prevents the operators from being presented with the information necessar:y to determine the status of the plant and to bring the plant to, and maintain it in, a safe condition following that accident. Furthermore, provision of two channels allows a CHANNEL CHECK during' the post accident phase to confirm the val idi*ty of displayed information, The exception to the two channel requirement is primary containment isolation valve (PCIV) position. In this case, the important information 1s the status of the primary containment penetrations. The LCO requires one position indicator for each active PCIY. This is sufficient to redundantly verify the isolation status of each isolable penetration either via indicated status ~f the active valve and prior knowledge of passi\le val*ve or via system boundary status. If a normally active PCIV is known to be closed and deactivated, position indication is not needed to determine status. Therefore, the position indication for valves in this state is not required to be OPERABLE.
{continued)
* PBAPS UNIT 2                        B 3.3-66                    Revision No. 0
 
PAM Instrwnentation B 3.3.3.1
* BASES LCO          The following list is a discussion of the specified (continued) instrument Functions listed in Table 3.3.3.1-1 in the accompanying LCO.
: 1. Reactor pressure Instruments:    PR-2-2-3-404 A, B Reactor pressure is a Category I variable provided to support monitoring of Reactor Coolant System {~CS) integrity and to verify operation of the Emergency Core Cooling Systems (ECCS). Two independent pressure transm1tters with a range of O psig to 1500 psig monitor pressure and associated independent w.i de range recorders are the primary indication used by the operator during an accident.
Therefore~ th~ PAM Specification deals specifically with this portion of the instrument channel.
: 2. 3. Reactor Vessel Water Level <Wide Range and Fuel Zone)
Instruments:    Wide Range: LR:-2-2-3-110 A, B {Green Pen) fuel Zone: LR-2-2-3-110 A, B (Blue Pen)
Reactor vessel-water level is a Category-1 variable provided to support DlOnitoring of core cooling and to-verify
* operation of the ECCS. The wide range and fuel zone water level channels provide the PAM Reactor Vessel Water Level Functions. The ranges of the wide range water level channels and the fuel zone water level channels overlap to cover a range of -325 inches (just below the bottom of the active fuel) to +50 inches (above the nonnal water level).
Reactor vessel water level is measured by separate differential pressure transmitters. Th& output from these channels is recorded on two independent pen recorders, which is the primary indication used by the operator during an accident. Each recorder has two channels, one for wide range reactor vessel water level and one for fuel zone reactor vessel water level. The.re fore, the PAM.
Specification deals specifically with these portions of the instrument channels.        -
(contjnued)
* PBAPS UNIT 2                  B 3.3-67                      Revision No. 7
 
PAM Instrumentation B 3 .. 3.3.1 BASES LCO          4. Suppression Chamber Water Level <Wide Range}
(continued)
              .Instruments:    LR-8123 A, B Suppression chambe.r water level is a Category I variable provided to detect a breach in the reactor coolant pressure boundary {RCPB). This variable is also used to verify and pro.vide long tenn surveillance or ECCS function. The wide rarige suppression chamber water 1evel measurement provides the operator with sufficient infonnation to assess the status of both the RCPB and the water supply to the Eccs.
The wide range water level recorders monitor the suppression chamber water level from the bottom of the ECCS suction l i nes to five feet above normal water level . Two wide range suppression chamber water level signals are transmitted from separate differential pressure transmitters and are.
continuously recorded on two recorders in the control room.
These recorders are the primary indication used by the ope.rater duri,ng an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel .
* s, 6. PrvweJJ Pressure <Wide Range and Subatmospheric Range}
Instruments: Wide Range:            PR-8102 A, B {Red Pen)
Subatmospheric Range: PR-8102 A, B (Green Pen)
Drywell pressure is a Categor:y I variable provided to detect breach of the RCPB and to verify ECCS functions that operate to maintain RCS integrity. The wide range and subatmospheric range drywell pressure channels provide the PAM Drywell Pressure Functions. The wide range and subatmospheric range drywe11 pressure channels overlap to cover a range of 5 psia to 225 psig (in excess of four times the design pressure of the drywell). Drywell pressure signals are transmitted from separate pressure transmitters and are continuously recorded and di sp*l ayed on two independent control room recorders. Each recorder has two channels, one for wide range drywell pressure and one for subatmospheric range drywell pressure. These recorders are the primary indication used by the operater during an accident. Therefore, the PAM Specification deals specifically with these portions of the instrument channels~
                                                                    <continued}
* PBAPS UNIT 2                    B 3.3-68                      Revision No. 3
 
PAM Instrumentation B 3.3.3.1
* BASES LCO (continued)
: 7. Drywell High Range Radiation Instruments:      RR-8103 A, B Drywell high range radiation is a Category I variable provided to monitor the potential of significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans. ~ost accident drywell radi~tion levels are monitored by four instrument channels each with a range of 1 to lxl0 8 R/hr. These radiation monitors drive two dual channel recorders 1ocated in the contra l room. Each recorder and the two associated channels are in a separate division. As such, two recorders and two channels of radiation monitoring instrumentation (one per recorder) are required to be OPERABLE for compliance with this LCO. Therefore, the PAM Specification dea 1s specifi ca 11 y with these portions of the i nst,rument channe 1s.
* 8,    Primary Containment Isolation Valve CPCIV) Position PCIV position is a Category I variable provided for verification of containment integrity, In the case of PCIV position, the important information is the isolation status of the containment penetrati.on. The LCO requires one channel of valve position indication in the control room to be OPERABLE for each active PGIV in a containment penetration flow path, i.e., two total channels of PCIV
* positio.n indtc*ation for a penetration f1ow path with two*
active valves. For containment penetrations with only one active PCIV having control room indication, Note Cb) requires a single channel of v,alve position indjcation t.o be OPERABLE. This is sufficient to redundantly verify the
* i5olation status of each iso1~ble penetration via indicat~d status of the active valve, a.s applicable, and prior knowledge of passive valve or system bour;idary .status. If a penetration flow path is isolated, position indic~tion for the PCIV(s) in the associated penetration flow path is not needed to determine status. Therefore, the position indication for valves in an isolated penetration flow path is not required to be OPERABLE. The PCIV position PAM instrumentation consists of position switches, associated wiring and control room indicating lamps for active PtIVs (check valves and manual valves are not required to have position indication). Therefore, the PAM Specification deals specifically with thes,e instrument channels.
Each penetration is treated sepaNtely and each penetration flow path is considered a .separate function. Therefore, separate condition entry is allowed for each inoperable penetration flow path .
* PBAPS UNIT 2                      B 3.3-69 (continued)
Revision No. 57
 
PAM Instrumentation B 3.3.3.1
* BASES LCO (continued) 9, 10. o*eJ etect
: 11. Suppression Chamber Water Temperature
* Instruments:        TR-8123 A, B TIS-2-2-71 A, B Recorders Suppression chamber water temperature is a Category I variable provided to detect a condition that could potentially lead to containment breach and to verify the effectiveness of ECCS actions taken to prevent containment breach. The suppression chamber water temperature instrumentation allows opera:tors to detect trends in suppression chamber water temperature in sufficient time to take action to prevent steam quenching vibrations in the suppression pool. Suppression chamber water temperature is monitored by two redundant channels . .Each channel is assigned to a separate safeguard power division. Each channel consists of 13 resistance temperature detectors (RTDs) mounted in thermowells installed in the suppression chamber shell below the minimum water level, a proces.sor, and control room recorders. The RTDs are mounted in each of 13 of the 16 segments of the suppression chamber. The RTD (continued)
* PBAPS UN IT 2                      B 3.3-70                    Revision No. 55
 
PAM Instrumentation B 3.3.3.1
* BASES LCD (continued)
: 11. Suppression Chamber Water Temperature Coonti nued) inputs are averaged by the processor to provide a bulk average temperature output to the associated control room recorder. The allowance that only 10 RTDs are ~equired to be OPERABLE for a channel to be considered OPERABLE provided no 2 adjacent RTDs are inoperabl is acceptable based on engineering judgement considering the temperature* response profile o*fthe suppression chamber water volume for previously analyzed events and the most challenging RTOs inoperable. These recorders are the prima.ry indication *Used by the operator during an accident. Therefore, the PAM S~ecification deals specifically with this portiorr of the instrument channels. Four recorders are provided. A recorder in each division is required to be OPERABLE to sat"i sfy the LC0.
APPLICABILITY      The PAM instrumentation LCO is applicable in MODES 1 and 2.
These variables are related to the diagnosis and preplanned actions required to mitigate DBAs. The applica-blt! DBAs are assumed to occur in MODES 1 and 2. In MODES 3, 4, and 5,
* plant conditions are such that the likelihood of an event that would require PAM instrumentation is extremely low; therefore. PAM instrumentation is not required to be OPERABLE in these MODES.
ACTIONS A Note has been provided to modify the ACTIONS related to PAM instrumentation channels. Section 1.3, Completion Ti mes, s.pe;ci fies, that once a Condi ti on has been entered, subsequent di visions, subsystems, components, or v,ari ables expressed in the Condition discovered to be inoperable or not within limits, will not result irr separate entry 'into the Condition. Section 1.3 also specifies that Required Actions of the. Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for
* PBAPS UN IT 2                            B 3.3-71 (contihued)
Revision No. 52
 
PAM Instrumentation B 3.3.3.1 BASES ACTIONS (continued) inoperable PAM instrumentation channels provide appropriate compensatory measures for separate FunctiOns. As such, a Note has been provided that allows separate Condition entry for each inoperable PAM Function.
AJ.
When one or more Functions have one required channel that is inoperable, the required inoperable channel mus~ pe restored to OPERABLE status wi tfli n 30 days. The 30 day Comp 1et ion Time is .based on operating experience and takes into account the remain1ng OPERABLE channels (or, in the case of a Functio.n that has only one required channel, other non-Regulatory Guide l.97 instrument channels to monitor the Function)~ the passive nature of the instrument (no critical automatic. action is assumed to occur from these instruments), and the low probability of an event requiring PAM instrumentation during this interval *
* If a channel has not been restored to OPERABl:..E status in 30 days, this Required Action specifies initiation of action 1n accordance with Specification 5.6.6, which requires a written report to be submitted to the NRC. This report discusses the results of the root cause evaluation of the i noperabi 1 ity and i dent i fies proposed restorative actions ..
Tnis action is appropriate in lieu of a shutdown requirement, since alternative actions are identified before loss of functional capability, and given the likelihood of plant conditions that would require infonnat1on provided by this instrumentation.
* C.l When one or more Functions have two required channels that are inoperable (i.e., two channels inoperable in the same Function), one channel in the Function should be restored to OPERABLE status within 7 days. The Completion Time of 7 days 1s based on the relatively low probability of ah event requiring PAM instrument operation and the availability of alternate means to obtain the required infonnati-On. Continuous operatton with two required
{continued}
PBAPS UNIT 2                    B 3.3-72                        Revision No. 3
 
PAM Instrumentation B 3.3.3.1
* BASES ACTIONS      Ll (continued) channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance qualification requirements applied to the PAM instrumentation. Therefore, requiring restoration of one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an acc.i dent occur.
lhl This Required Action directs entry into the appropriate Condition referenced in Table 3.3.3.1-1. The applicable Condition referenced in the Table is Function dependent.
Each time an inoperable channel has not met the Required Action of Condition C and the associated Completion Time has expired, Condition Dis entered for that channel and provides for transfer to the appropriate subsequent Condition.
Ll
* For the majority of Functions in Table 3.3.3.1-1, if the Required Action and associated Completion Time of Condition -C is not met-,. the plant must be-brought to, a MODE in whic-h the. LCD not apply. To achieve this status, the ,
plant must be brought to at least MODE 3 within 12 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.
Ll Since alternate means of monitoring drywell high range radiation have been developed and tested, the Required Act ion is not to shut down the pl ant, but rather to fo.11 ow the directions of Specification 5.6.6. These alternate means may be temporarily installed if the nonnal PAM channel cannot be restored to OPERABLE status within the allotted time. The report provided to the NRC should discuss the alterna_te means used, describe the degree to which the alternate means are equivalent to *the installed PAM channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the nonual PAM channe.l s.
(continued)
PBAPS UNIT 2                    B 3.3-73                      Revision No. 3
 
PAM Instrumentation B 3.3.3.1
* BASES  (continued)
SURVEILLANCE REQUIREMENTS SR  3.3.3.1.1 P'erformance of the CHAN-NEL CHECK once every 31 days ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an 1ndication of excessive instrument drift in one of the channels or something even more serious: A CHANNEL CHECK will detect gross channel fai.lure; thus, it is key to verifying th.e instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared to similar plant instruments located throughout the plant.
Agreement criteria are determined by the pl ant staff, based on a combination of the channel instrument uncertainties, including isolation, indication, and readability. If a channel is outside the criteria, it may be an indication
* that the sensor or the signal processing equipment has drifted outside its limit.
The Surveill9nce Frequency is controlled -und-er th-e Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of thos displays associated with the Ghannel s requ'i re.ct by the LCO.
SR  3.3,3.1.2 Deleted SR  3.3.3.1.3 These SRs require CHANNEL CALIBRATIONs to be performed. A CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies the channel responds to measured parameter with the necessary range and accuracy. For the PCIV Position Function, the CHANNEL CAl.LBRATION consists of verifying th*e remote indication conforms to actual valve position .
* PBAPS UN IT 2                        B 3.3-74                        Revision No. 86
 
PAM Instrumentation B 3.3.3.1
* BASES
  -------------~---------------------
SURVEILLANCE SR  3.3,3,1,3  (continued)
REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
REFERENCES  1. Regulatory Guide l.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Envi rans Conditions During and Foll ow1 ng an Accident,"
Revision 3, May 1983.
: 2. NRC Safety Evaluation Report, "Peach Bottom Atomic Power Station, Unit Nos. 2 and 3j Conformance to Regulatory Guide 1.97," January 15, 1988.
: 3. Letter from G. Y. Suh CNRC) to G. J. Beck (PECo) dated February 13, 1991 concerning "Conformance to Regulatory Gui de 1.97 for Pe.a ch Bottom Atomic Po,wer Station, Units 2 and 3".
: 4. Letter from S. Dembek (NRC} to G. A. Hunger (PECO Energy) dated March 7, 1994 concern-fng "Regulatory
* Guide 1.97 - Boiling Water Reactor Neutron Flux Monitoring, Peach Bottom Atomic Power Station CPBAPS),
Units 2 and 3" .
* PBAPS UNIT 2                  B 3.3-?5                      Revision No. 86
 
Remote Shutdown System B 3.3.3.2
* B 3.3  INSTRUMENTATION B 3.3.3,2 BASES Remote Shutdown System BACKGROUND        The Remote Shutdown System provides the control room operator with sufficient instrumentation and controls to maintain the plant in a safe shutdown condition from a location other than the control room for at least one hour.
This capabi11ty is necessary to protect against the possibilfty of the control room becoming inaccessible. A s*afe shutdown condition is defi n,ed as M0Df 3. With the plant in MODE 3, the Reactor Core Isolation Cooling (RCIC)
System and the safety/relief valves can be used to remove core decay heat and meet all safety requirements. The long term supply of water for the RCIC and the ability to control reactor pressure arid level from outside the control room allow extended operation in MODE 3.
In the event that the control room must be abandoned, a reactor trip and MSIV closure is assumed to nave been i nit i at ed from t he co nt r o1 room pr i o r to a!)a ndo nm en t . Fo r the design event, it is assumed the loss of feedwater (as a result of MSJV closure) causes an automatic start of RCIC due to low reactor level. Although HPCI also typically initiates on low reactor level, it is c6nservatively ass-urned that it does not start for the design event ~ue to damage in the control room. No LOOP, accident condttion or other failures are assumed. At the remote shutdown panel, reactor level and pressure is maintained with RCIC and operation of SRVs H, E and L. SRV operation maintains pressure below the SRV lift setpoint and transfers decay heat to the suppression pool. This can be maintained for at least one hour without suppression pool cooling. If control room access cannot be regained in one hour, procedures provide direction to bring the plant to cold shutdown.
The OPERABILITY of the Remote Shutdown System ensures there are sufficient controls and information availab1e for those plant par,ameters necessary to maintain the plant in MODE: 3 for at least one hour. Other controls and indication on the remote shutdown parnel are provided, but they are not required for OPERABILITY.
APPLICABLE        The Remote Shutdown System is required to provide SAFETY ANALYSES    instrumentation and controls at appropri.ate 1ocations outside the control room with a design capability to control reactor pressure and level, including the necessary instrumentation arid controls, to maintain the plant in a safe condition 1n MODE 3.
PBAPS UNIT 2                            B 3,3                          Revision No. 132
 
Remote Shutdown System B 3.3.3.2
* BASES APPLICABLE SAFETY ANALYSES (continued)
The criteria governing the design and the specific system requirements of the Remote Shutd,own System are located in the UFSAR (Refs. 1 and 2).
The Remote Shutdown System is considered an important contributor to reducing the risk of accidents; as such, it meets Criteri.011 4 of the. NRC Policy Statement.
The Remote Shutdown Sys.tern LCO provides the requirements for the OPERABILITY of the instrumentation and controls necessary to maintain the plant 1'11 Moot .3 from a location other than the control room. The instrumentation and controls required are listed in Table B 3.3.3.2-1.
The controls, instrumentation, and transfer switches are those required fo.r:
* Reactor pressure vessel (RPV) pressure control;
* Decay heat rernova 1 ; and
*
* RPV inventory control Ihe Remote Shutdown System is OPERABLE if all instrument and cor;itrol channels needed to support the remote shutdown function are OPERABLE.
The Remote Shutdown System instruments and control circuit5 covered by_this LCO do not need to be energized to be considered OPERABLE. This LCO is intended to ensure that the instruments and control ci rc.uits will be OPERABLE if plant conditions require that the Remote Shutdown System be placed in operatton.
APPLICABILITY    The Remote Shutdown System LCO is applicable in MODES 1 an ct 2 . 1h i s i s re qui r ed s o th a t t he p1 a nt ca n be ma i nta i ne d in MODE 3 for an extended period of time from a location other than the control room .
* PBAPS UN IT 2                                                              Revision No. 132
 
Remote Shutdown System B 3.3.3.2
* BASES APPLICABILITY (continued)
This LCD is not applicable in MODES 3, 4, and 5 .. In these MODES. the plant is already subcritical and in a condi.tion of reduced Reactor Coolant System energy. Under these conditions, considerable time is available to restore necessary instrument control Functions if control room instruments or control becomes unavailable. Consequently, the TS do not require OPERABILITY in MODES 3, 4, and 5.
ACTIONS A Note has been provided to modify the ACTIONS related to Remote Shutd-0wn System Fu.nctions. Section L3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable Remote Shutdown System Functions provide appropriate compensatory measures for separate Functions.
As such, a Note has been provided that allows separate Condition entry for each inoperi;ib1e Remote Shutdown System Fu.net ion.
A.1 Condition A addresses the situation where one or more required Functions of the Remote Shutdown System is inoperable. This includes the control and transfer switches for any required function.
The. Required Action "is to restore th*e Function (all required channels) to OPERABLE status within 30 days. The Completion Time is based on operat~ng experience and the low probability of an event that would require evacuation of the control room .
* PBAPS UN IT 2                  B 3,3-78                      Revision No. 52
 
Remote Shutdown System B 3.3.3.2 I BASES ACTIONS        Ll (continued)
If the Required Action and associated Completion Ti.me of Condition A are not met, the plant must be brought to a MODE il'il which the LCO does not apply. To achieve this status,.
the plant must be brought to at least MODE 3 within 12 hours. The allowed Co.mpletion Time js reasonable, based on operating experience, to reach the required MODE from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE  SR    3.3.3,2,1 REQU I REMtNTS SR 3.3.3.2.1 verifies that each instrument and control circuit in Table B 3.3.3.2-1 performs t~e intended fuhction.
This verification is performed from the remote shutdown panel and locally, if necessary. Operation of equipment from the remote shutdown panel is not necessary. The Surveillance can be satisfied by performance of a continuity che.ck Of the circuitry. This will ensure that if the control room becomes inaccessible, the pl ant can 'be maintained in MODE 3 from the remote shutdown panel. Each required transfer switch and circuit is limited to those that are necessary to maintain reactor_ level and pressure from the remote shutdown panel during operation in Mode 3, The Surveillance Frequency is controlled under ~he Surveillance Frequency Contro1 Program.
SR    3 *3 . 3 , 2 ,. 2 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. The test veri ft es the channel responds to measured parameter values with the necessary range and accuracy. The Survei 11 ance F,requency is controlled under the Surveillance Frequency Control Program.
REFERENUS      1.      UFSAR, Section L5.1.
: 2.      UFSAR, Section 7.18.
: 3.      Drawing E-540-13.
: 4.      IR 2556042.
I PBAPS UNIT 2                            B 3.3-79                Revision No. 132
 
Remote. Shutdown Sys tern B 3.3.3.2 Table B 3.3.3.2-1 (page 1 of 3)
Remote Shutdown System Instrumentation FUN CTI ON                                REQUIRED NUMBER OF CHANNELS Instrument Parameter
: 1. Reactor Pressure                                        2
: 2. Reactor Level (Wide Range)                              2
: 3. Torus Tempera tyre                                      2
: 4. Torus Level                                            1
: 5. Condensate Storage Tank Level                          1
: 6. RCIC Flow                                              1
: 7. RCIC Turbine Speed                                      1
: 8. RCIC Pump Suction Pressure                              1
* 9.
10.
11.
RCIC Pump Discharge Pressure RCIC Turbine Supply Pressure RCIC Turbine Exhaust Pressure 1
1 1
: 12. Drywel l Pressure                                      1 Transfer/Control Parameter
: 13. RCIC Pump Flow                                          1
: 14. RCIC Drain Isolation to Radwoste                        1
: 15. RCIC Steam Pot Drain Steam T~ap Bypass                  1
: 16. RCTC Drain Isolation to Mairi Condenser                1
* PBAPS UN IT 2 B 3.3-80                    Revision No. 132
 
Remote Shutdown System B 3.3.3.2
* FUNCTION iable B 3.3.3.2-1 (page 2 of 3)
Remote Shutdown System Instrumentce1tion REQ:UI RED NIUMBER OF CHANNELS Transfer/Control Parameter    Ccont 1nued)
: 17. RCIC Exhaust Line Drain Isolation                            2 (1/va l ve)
: 18. RCIC Steam Isolation                                        2 (1/va 1ve)
: 19. RCIC Suction from Condensate Storage Tank                    1
: 20. RCIC Pump Discharge                                          2 (1/va l ve)
: 21. RCIC M.inimum Flow                                          1
: 22. RGIC Pump Discharge to FuT l Flow Test Line                  1
: 23. RCIC Suction from Toru.s                                    2 Cl/valve)
: 24. RCIC Steam Supply                                            1
: 25. RCIC Lube Oil Cooler Valve                                  1
: 26. RCIC Trip Throttle Valve Operator Position                  1
: 27. RCIC Trip Throttle Valve Position                            I
: 28. RCIC Vacuum Breaker                                          1
: 29. RCIC Condensate Pump                                          1
: 30. RCIC Vacuum Pump                                              1
: 31. Safety/Relief Valves CS/RVs)                                  3 Cl/valve)
PBAPS UNIT 2                          B 3.3-81                      Revision No. 132
 
Remote Shutdown System B 3.3.3.2
* FUNCTION Table B 3.3.3.2-1 (page 3 of 3)
Remote Shutdown System Instrumentation REQUIRED NUMBER OF CHANNfLS Transfer/Control p.a rameter  (continued)
: 32. Auto Isolation Reset                                      2 (1/dtvi sion)
: 33. Instrument Transfer                                      5 Cl/transfer switch)
PBAPS UNIT 2                        B 3.3-82                    Revision No. 132
 
ATWS-RPT Instrumentation B 3.3.4.l
* B 3.3  INSTRUMENTATION B 3.3.4.1  Anticipated Transient Without Scram Recirculation 'Pump Trip (ATWS-RPT) Instrumentation
  &ASES BACKGROUND        The ATWS-RPT System initiates an RPT, adding negative reactivity, following events in which a scram does not (but should) occur, to lessen the effects of an ATWS event.
Tripping the rec:iri'.:ulation pumps adds negative reactivity from the increase in steam voiding in the core area as core fl ow decreases. When Reactor Vessel Water Level - low Low (Level 2) or Reactor Pressure-High setpoint is reached, the recirculation pump motor breakers trip.
The ATWS-RPT System includes sensors, relays, and switches that are necessary to cause initiation of an RPT. The channels include electronic equipment that compares measured input signals with pre-,establ i shed se.tpoi nts. When the setpoint is exceeded, the channel output relay actuates, which then outputs an ATWS-RPT signal to the trip logic.
The ATWS-RPT consists of two trip systems. There are two ATWS-RPT Functions: Reactor Pressure-High and Reactor Vessel Water Level - Low Low ( Leve] 2). Each trip system has two chann_els of Reactor Pressure-High a.nd two ch,anne1s of Reactor Vessel Water Level-Low Low (Level 2). Each ATWS-RPT trip system is a one-out-of-two logic for each Function. Thus, one Reactor Water Level-Low Low {Leve1 2).
or orre. Reactor Pressure-High signal is needed to trip a trip system. Both trip systems must be in a tripped condition to initiate the trip of both recirculation pumps (by tripping the respective recirculation pump motor breakers). Each recirculation pump has two breakers in series to disconnect the power to the recirculation pump motor. A dedicated trip mechanism is provided to each breaker for the ATWS signal. When the ATWS signal is initiated via the reactor pressure high or reactor level low-low, these breakers will trip automatically and discontJect th.e power to the mot_or.
APPLICABLE        The ATWS-RPT is not assumed in the safety analysis. The SAFETY ANALYSES,  ATWS-RPT initiates an RPT to aid in preserving the integrity LCO, and          of the fuel cladding following events in which a scram does APPLICABILITY      not, but should, occur. Based on its contribution to the reduction of overall plant risk, however, the instrumentation meets Criterion 4 of the NRC Policy Statement .
* PBAPS UN IT 2                        B 3.3-83                      Revision No. 115
 
ATWS-RPT Instrumentation B 3.3.4.1
* BASES APPLICABLE SAFETY ANALYSES, LCO, and The OPERABILITY of the ATWS-RPT is dependent on the OPERABILITY of the individual instrumentation channel Functions. Each Function must have a required number of APPLICABILITY    OPERABLE channels in each trip system, with their (continued)    setpoints within the specified Allowable Value of SR 3.3.4.1.3. The actual setpoint is calibrated consistent with app1icable setpoint methodology assumptions. Channel OPERABILITY also includes the associated recirculation pump dri-ve motor breakers. A channel is inoperable if its actual trip setting is not within its required Allowable Value.
Allowable Values are specified for each ATWS-RPT Function specified in the LCO. Trip setpoints are specified in the setpoint calculations.. The trip setpotnts are .selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setting less conservative than the. trip setpoi nt, but within its Allowable Value, is acceptable. Trip setpoints are those predetennined values of output at which an action should take place. The setpoints ate compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device changes state .
The analytic or design limits are derived from the limiting values of the process parameters obtatned from the safety analysis.-- The Allowable Values are-derived-from the - -
analytic o-r design l iaaits, corrected for calibration, process, and instrument errors as well as instrument drift.
In selected cases,. the Allowable Values and trip setpoints are determined by engineering judgeinent or historically accepted practice relative to the intended function of the channel: The trip setpoints determined in this manner provide adequate protection by assuring instrument and process uncertainties expected for the environments during the operat i,ng. time of the assod ated channe1s are accounted for.
The i.ndividual Functions are required to be OPERABLE in MODE I to protect against common mode failures of the Reactor Protection System by providing a diverse trip to mitigate the consequences of a postulated ATWS event. The Reactor Pressure-High and Reactor Vessel Water level-Low Low (Level 2) Functions are required to be OPERABLE in MODE 1 since the reactor- is producing significant power and
{continued)
  .PBAPS UN IT 2                        B 3.3-84                    Revts1on No. o
 
                                                      - ATWS-RPT Instrumentation B 3.3.4.1
* BASES APPLICABLE      the recirculation system could be at high f1ow. Duri.ng this SAFETY ANALYSES, MODE, the potential exists for pressure increases or low LCO, and        water level, assuming an ATWS event. In MODE 2, the reactor APPLICABILITY    is at low power and the recirculation system is at low flow; (continued)  thus; the potential is low for a pressure increase or low water level, assuming an .ATWS event.. Therefore, the ATWS-RPT is not necessary. In MODES 3 and 4, the reactor is shut down with all control rods inserted; thus, an ATWS event is not signfficant and the possibility of a significant pressure increase or low water level is negligible. In MODE 5, the one rod out interlock ensures that the teactor remains subcritical; thus, an ATWS event is not signi.ficant. In addition, the reactor pressure vessel (RPV) head is not fully tensioned and no pressure transient threat to the reactor coolant pressure boundary (RCPB) exists.
The specific Applicable Safety Analyses and LCO discussions are listed below on a Function by Function basis.
a*  Reactor Vessel Water Level-Low Low {Level 2)
* Low RPV water level indicates that a reactor scram should have occurred and the capabfl ity to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. The ATWS-RPT System is initiated at Level 2 to assist in the. mitigation of the ATWS event. The resultant reduction of core flow reduces the neutron flux and THERMAL POWER and, therefore, the rate of coolant boil off.
Reactor vessel water level signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.
Four channels of Reactor Vessel Water Level-Low low (Level 2), with two channels in each trip system, are available and required to be. OPERABLE: to ensure that no single instrUJDent failure can preclude an ATWS-RPT from this Function on .a valid signal. The Reactor Vessel Water Level-Low Low (Level 2) Alfowab1e Value (contjn1:1edl PBAPS UNIT 2                      8 3.3-85                      Revision No. O
 
ATWS-RPT Instrumentation B 3.3.4.l
* BASES APPLICABLE      a. Reactor Vessel water Level-Low Low {teveJ 21 SAFITY ANALYSES,      {continued)
LCO, and APPLICABILITY          is chosen so that the system will not be initiated after a Level 3 scram with feedwater still available, and for convenience with the reactor core isolation cooling initiation.
: b. Reactor Pressure-High Excessively high RPV pressure may rupture the ~CPB.
M increase in the RPV pressure during reactor operation compresses the steam voids and results in a positive reactivity insertion. This increases neutron flux and THERMAL POWER, which could potenti a1ly result in fuel failure and overpressurization. The Reactor Pressure-High Function initiates an RPT for transients that result :in a pressure increase, counteracting the pressure increase by rapidly reducing. core power generation. For the overpressurization event, the RPT aids in the tennination of the ATWS event and, along
* with the safety/relief valves, limits the peak RPV pressure to less than the ASME Section III Code limits.
* The Reactor Pressure-High signals are initiated from
                        .four pressure transmitters that ,monitor reactor steam dome pressure. Four channels of Reactor Pressure-High, with two channels in each trip system, are available a~d are required to be OPERABLE to ensure that no single instrument failure can preclude an ATWS-RPT from this Function on a valid signal. The Reactor Pressure-High Allowable Value is chosen to provide an adequate margin to the ASME Section III Code limits.
ACTIONS          A Note has been provided to modify the ACTIONS related to ATWS-RPT instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the CondiUon. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each (continued)
PBAPS UNIT 2                      B 3.3-86                      Revision No. O
 
ATWS .. RPT Instrumentation B 3.3.4.1
* BASES ACTIONS (continued) additional failure, with Comple.tion Times based on initial entry into the Condition. However, the Required Actions for inoperable ATWS-RPT instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such; a Note has .been provided that a11 ows separate Condition entry for each inoperable* ATWS-RPT instrumentation channel.
A,l and A.2 With one or more channels inoperable, but with ATWS-RPT trip capability for each Function aia i nta i ned (refer to Required Actions 8.1 and C.1 Bases), the ATWS-RPT System is capable of performing the intended function.. However, the re1iability and redundancy of the ATWS-RPT instrtnnentation is reduced, such that a single failure in the remaining trip system could result in the 1nabil ity of the ATWS-RPT System to perform the intended function. Therefore, only a limited time is allowed to restore the inoperable channels to OPERABLE status. Because of the diversity of sensors avail able to provide trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of ATWS-RPT, 14 days is provided to restore the inoperable channel *(Required Action A.I). Alternately, the inoperable channel may be placed in trip (Required Action A.2), since this would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. As noted, placi~g the channel in trip with no further restrictions is not allowed if the. inoperable channel is the result of an inoperable breaker, since this may not adequately compensate for the inoperable breaker (e.g., the brealcer may be inoperable such thijt it will not open)~ If it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel would result in an RPT), or if the inoperable channel is the result of an inoperable breaker, Condition D must be entered and its Required Actions taken *
                .Ll.
Required Action 8.1 is intended to ensure that approp.riate actions are taken if multiple, inoperable, untripped channels within the same Function result in the Function not
{continued)
PBAPS UNIT 2                    B 3.3-87                            Revision No. 0
 
ATWS-RPT Instrumentation B 3 .. 3.4.1
* , BASES ACTIONS      lJ. (continued) maintaining ATWS-RPT trip capability. A Function is considered to be maintaining ATWS-RPT trip c~pability when sufficient channels are OPERABLE or in trip such that the ATWS-RPT System will generate. a trip, signal from the given Function on a valid signal, and both recirculation pumps can be. tripped. This requires one channel of the Function in each trip system to be OPERABLE or in trip, and the recirculation* pump dr1Ve motor breakers to be OPERABLE or in trip.
The 12*hour Completion Time is suffici.ent for the operator to take corrective action (e.g., restoration or trtpping of channels) and takes into account the likelihood of an event requiring actuation of the ATWS-RPT instrumentation during this period and that one Function is still maintaining ATWS-RPT trip capability.
Ll Requi.red Action C.* l is intended to ensure that appropriate Actions are taken if IMlltiple, inoperable, untripped channels within both Functions result in both Functions not maintaining ATWS-RPT trip capabil Uy. The description of a Function maintaining ATWS-RPT trip capabil i.ty is discussed in the Bases for Required Action B.l above.
The 1 hour Completion Time is sufficient for the operatqr to take corrective action and takes into account the likelihood of an event requiring actuation of the ATWS-RPT instrumentation during thi.s period.
D,l and 0,2 With any Required Action and associated Completion Time not met, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 2 within 6 hours (Required Action D.2). Alternately, the associated recirculation pwnp may be .removed from service since this.
performs the intended function of the instrumentation.
(Required Action D.l). The allowed Completion Time of
{continued)
PBAPS UNIT 2                  B 3.3-88                      Revision No. 0
 
ATWS-RPT Instrumentation B 3.3.4.1
* BASES ACTIONS      D.1 and D,2        *(continued) 6 hours is reasonable, based on operating experi et1ce, both to reach MODE 2 from full power conditions and to remove a recirculation pump from service in an orderly manner and without challenging plant systems.
Required Action D.1 is modified by a Note which states that the Required Action is only applicable if the inoperable channel is the result of*an inoperable RPT breaker. The Note clarifies the situations under which the associated Required Action would be the appropriate Required Action.
SURVEILLANCE  The Surveillances are modified by a Note to indicate that REQUIREMENTS  when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into the associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains ATWS-RPT trip capability. Upon completion of the Sur ve il l a nce , o r exp i rat i on of t he 6 hour a11 ow a nce , t he channel must be returned to OPERABLE status or the app1icable Condition entered and Requil"'ed Actions taken.
This Note is based on the reliability analysis (Ref. 1) a.ssumption of the average time required to perform channel S~rveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the recirculation pumps will trip when necessary.
SR  3.3.4.1.1 Performance of t~e CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECk is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It ts based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.
Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious, A CHANNEL CHECK will detect gross channel failure; thusj it is key to verifying the instrumentation continues to operate properly
              'between each CHANNEL CALIBRATION.
Agreement criteria are determined by the plant staff based on a combination of the channel instrument unc~rtatnties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.                    *
* PBAPS UNIT 2                          B 3.3-89                          Revision No, 86
 
ATWS-RPT Instrumentation B 3.3.4.l
* BASES SURVEILLANCE SR  3.3,4.1,1    (continued)
REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements. less formal, but more frequent, chec'ks of channels during norma1 opera.tfonal use of the displays associated with the required channels of this LCO.
SR  3.3,4,1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with t~e assumptions of the current plant specific s.etpoi nt methodology .
The Surveillance Frequency is controlled under the Survei 11 ance Frequency Control Program ..
SR  3.'3,4.L3
* A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary ran~e and accu~acy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between s~ccessive calibrations, consistent With the assumptions of t~e current plant specific setpoint methodology.
The Surveillqnce Frequency is controlled under the Surveillance Frequency Control Program.
SR  3,3.4,1.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the pump breakers is included as part of this Surveillance and overlaps the LOGIC SYSTEM FtJNCTIONAL TEST to provide complete testing of th*e assumed safety function. Therefore, if a breaker is i ncapab.l e of operating, the associated instrument channel ( s) would be inoperable .
* PBAPS UNIT 2                      B 3.3-90                  Revision No. 86
 
                                                        ~TWS-RPT Instrumentation B 3.3.4.l
* BASES SURVEILLANCE  SR  3.3.4.1,4    (continued)
REQ,UI REMENTS The Surveillance Frequency is controlled under the Survei 11 ance Freque,ncy Contro1 Progr,atn.
REFERENCES    1. GENE-770-06-1, "Basei for Changes To Survei1lanGe Test Intervals and Allowed Out-of-Service Times For Se1 ecteE1 Instru_mentati on Technical Spec:1 fi cations,"
February 1991 .
* PBAPS UN IT 2                                                    Revision No. 86
 
EOC-RPT r~strwmentat1on B 3.3.4.2 B 3.3  INSTRUMl:NTATION B 3.3.4.2  End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation BASES BACKGROUND        The EOC-RPT instrumentation 1nit1ates a recirculation pump trip (RPT) to reduce the peak reactor pressure and power resulting from turb1 ne tr1 p or generator 1oad reject1 o_n transients and to minimize the decrease in core MCPR durfng these tran*st ents.
The benefit of the additional negative react1v1ty in excess of that normally inserted on a scram reflects end of cycle reactivity considerations. Flux shapes at the end of cycle are such that the control rod.s inse,rt only a small amount of negative reactivity during the ftrst few feet of rod travel upon a scram caused by Turbine Control Valve (TCV) Fast Closure, Trip Oil Pressure- Low or Turbine Stop Valve CTSV)-Closure. The pttysical phenomenon involved is that the void reactivity feedback due to a pressurization transient can add positive reactivity at a faster rate than the control rods can add negative reactivity .
* The EOC-RPT instrumentation, as shown in Reference 1, is composed of sensors that detect initiation of closure of the TSVs or fast closure of the TCVs, comb1ned w1th relays, log1c circuits, and fast ~ct1ng circuit breakers that interrupt power from the recirculation pump adjustable speed drives (ASDS) to each of the teG1rculat1on pump motors. When the setpo1nt is exceeded, the channel output relay actuates, which then outputs an EOC-RPT signal to the trip 1og1c. When the RPT bre~kers trip open, the recirculation pumps coast down under their own inertia. The EOC-RPT has two identical trip systems, either of which can actuate an RPT.
Each ~OC-RP1 trip system is a two-out-of-two logic for each Function; thu-s, e1ther two TSV-Closure or two rev Fast Closure, Tr1p 011 Pressure-Low s1gnals are required for a trfp sys.tern to actuate. If e1ther trip system actuates, both rec1 rcul ati on pumps w11 l tr1 p. Ther~ are two EOC-RPT breakers in series per recirculation pump. One trip system trips one of the two EOC-RPT breakers for each recirculation
                                                                            <continued)
* PBAPS UNIT 2                            B 3.3-9la                    Revision No. 137
 
EOC-RPT Instrumentation B 3.3.4.2
* BASES
    ----~-------------------~----------
BAG KG ROUND    pump, and the second trip system trips the other EOC-RPT (continued)    breaker for each recirculation pump.
APPLICABLE      The TSV-Closure and the TCV Fast Closure, Trip Oil SAFETY ANALYSES, Pressure- Low Functions are desi.gned to trip the LCO, and        recirculation pumps in the event of a turbine trip or APPLICABILITY    generator load rejection to mitigate the neutron f1ux, heat flux, and pressurization transients, and to minimize the decrease i 11 MCPR. The analytical' methods and assumptions used in evaluating the turbine trip and generator load rejection, as well as other safety analy~es that utilize e:oC-RPT, are su11111arized in References 2, 3, and 4.
To mitigate pressurization transient effects, the EOC-RPT must trip the recirculation pumps after initiation of closure movement of either the TSVs or the TCVs. The combined effects of this trip and a scram reduce fuel bundle power more rapidly than a scram a1 one so that the. Safety Limit MCPR is not exceeded. Alternatively, APLHGR operating limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), the MCPR operating limits (LCO 3.2,2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), and the LHGR oper:ating_ limits (LCO 3.2.3, ''LINEAR HEAT GENERATION RATE (LHGR)") for an inoperable EOC-RPT, as specified in the COLR, are sufficient to allow this LCO to be met. The EOC-RPT function is automatically disabled when turbine first stage pressure is < 26 ..3% RTP.
EOC-RPT instrumentation satisfies Criterion 3 of the NRC Policy Statement.
The OPERABILITY of the EOC-RPT is dependent on. the OPERABILITY of the individual instrumentation channel Functions, i.e., the TSV-Closure and the TCV Fast Closure, Trip Oil Pressure-Low Functions. Each Function must have a required number of OPERABLE channels in each trip system, with their setpoints within the specified A11 owab 1e Va1 ue of SR 3.3A.2.3. Channel OPERABILITY also includes the associated EOC-RPT breakers. Each channel (including the associated EOC-RP1 breakers) m~st also respond within its assumed response time.
A11 owab 1e Va1ues are specified for each EOC-RPT Function specified in the LCO. Trip setpoints are specified in the plant design documentation. The trip setpoints are selected
* PBAPS UNIT 2                        B 3.3-91b (continued)
Revision No. 143
 
EOC-RPT Instrumentation B 3.3.4.2
* BASES APPLICABLE SAFETY ANAL YSl:S, to ensure that the actual setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS.
LCO, and            Operation with a trip setpoint less conservative than the APPUCABlUTY          trip setpoint. but within its Allowable Value, is Ccont i nU d )  acceptable. A channel is inoperable if its actual trip setting is not within its required Allowable Va1ue. Trip setpoi.nts are those predetermin.ed values of output at which an action should take pla.ce. The setpoints are compared to the actual process parameters (e.g. TSV position), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., limit switch) changes state. The analytic limit for the TCV Fast Closure, Trip Oil Pressur*e-Low Function was determined based on the TCV hydraulic oil circuit design. The Allowable Value is derived from the analytic limit, corrected for calibration, process, and instrument errors. The trip setpoi nt is determined from the analytical limit corrected for calibration, process, and instrumentation errors, as well as instrument drift, as applicable. The Allowable Value and trip setpoint for the TSV-Closure Ft.rnction was determined by engine.ering judgment and historically accepted practice for similar trip functions .
The specific Applicable Safety Analysis, LCD, and Applicability discussions are listed below on a. Function by Function basis.
Alternatively, since the instrumentation protects agains~ a MCPR SL violation, with the instrumentation inoperable, modifications to the APLHGR operating limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) "), the MCPR operating limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)h), and the LHGR operating limits (LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)") may be applied to allow this LCO to be met. The appropriate MCPR operating limits and power-dependent thermal limit adjustments for the EOC-RPT inoperable condition are specified in the COLR.
Turbine Stop Valve-Closure Closure of the TSVs and a main turbine trip result in the loss of a heat sink that produces reactor pressurej neutron flux, and heat flux transients that must be limited.
Therefore, an RPT is initiated on TSV-Closure in anticipation of the transients that would result from closure of these valves. EOC-RPT decreases peak reactor power and aids the reactor scram in ensuring that the MCPR SL is not exceeded during the worst case transient .
co PBAPS UN IT 2                        B 3.3-9lc                    Revision No. 49
 
EOC-RPT Instrumentation B' 3 .. 3.4. 2
* BASES APPLICABLE      Turbine Stop Yalve-:Closure  (continued)
SAFETY ANALYSIS, LC0, and        Closure of the TSVs is determined by measuring the position APPLICABILITY    of each valve. There are position swi"tches assot.iated with e,ch stop valve, the signal from each switch being assigned to a separate trip channe7. The logic for the TSV-Closure Function is such that two or more TSVs must be closed to produce an EOC-RPT. This Function must be enabled at THERMAL POWER;;: 26.3% RTP as measured at the turbi.ne first stage pressure. This i.s normally accomplished automatically by pressure switches sensing turbine first stage pressure; therefore, opening of the turbine bypass valves may affect this Function. Four channels of TSV-Closure, with two channels in each trip system, are available and required to be OPERABLE to* ensure that no single instrument failure will preclude an E0C-RPT from this Function on a valid signal.
The TSV-Closure Allowable Valu*e is selected to detect imminent TSV c1osure.
This EOC-R.PT Function is required, consistent with the safety analysis assumptions, whenever THERMAL POWER is
                  ~ 26.3% RTP. Below 26.3% RTP, the Reactor Pressure-High
* and the Average Power Range Monitor (APRM) Scram Clamp Functions of the Reactor Protection System (RPS) are adequate to maintain the necessary safety margins.
Turbine Control Valve  Fast Oosure. Trio Oil Pressure - Low Fast closure of the TCVs during a generator load rejecti.on results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, ar:i RPT is initiated on TCV Fast Closure, Trip Oil Pressure-Low in anticipation of the transients tha:t wou1d result front the closure of these valves. The EOC-RPT decreases peak reactor power and aids the reactor scram in ensuring that the MCPR .SL is not exceeded during the worst case transient.
Fast closure of the TCVs is determined by measuring the el ectrohydraulic control fluid pressure at each control valve. There is one pressure switch associated with each control valve, and the, signal from each switch is assigned to a separate trip channel. The logic for the TCV Fast Closure, Trip Oil Pressure-Low Furtc:tion is such that two or more TCVs must be closed (pressure switch trips)
{continued}
* PBAPS UNIT 2                      B 3.3-91d                  Revision No. 143
 
E0C-RPT Instrumentation B 3.3.4.2
* BASES APPLICABLE SAFETY ANALYSIS LC0, and I
Turbine Contro1 Valve Fast Closure. Trio Oil Pressure:=Low (continued)
APPLICABILITY    to produce an EOC-RPT. This Function must be enabled at THERMAL POWER~ 26.3% RTP as measured at the turbine first stage pressure. This is normally accomplished automatically by pressure switches sensing turbine first stage pressure; therefore,. opening of the turbine bypass valves may affect this Function. Four channels of TCV Fast Closure, Trip Oil Pressure-Low, with two channels in eadl trip system, are available and required to be. OPERABLE to ensure that .no single instrument failure will preclude an EOC-RPT from this Function on a valid signal. The TCV Fast Closure, Trip Oil Pressur~-Low Allowable. Value is selected high eno1:1gh to detect imminent TCV fast closure.
This protection is required consistent with the safety analysis whenever THERMAL POWER is ~ 26.3% RTP.. Below 26.3% RTP, the Reactor Pressure-High and the APRM Scram Clamp Funct,ons of the RPS are adequate to maintain the necessary safety margins .
* ACTIONS          A Note has been provided to modify the ACTIONS related to E0C-RPT instrumentatioi:i channels. Section 1. 3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsyst~s, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into t~e Condition. Section 1.3 also specifies that Required Action*s of the Condition continue to apply for each additiona1 failure, with Completion Times based on ini.tial entry into the Condition. However, the Required Actions for inQperable EOC-RPT instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable EOC-RPT instrumentation channel~
{continued)
* PBAPS UNIT 2                        B 3.3-9le                  Revision No. 143
 
                                                                      )
EOC-RPT Instrumentation B 3.3.4.Z
* BASES ACTIONS (continued)
A....LJ.illLt\....2.
With one or more required channels inoperable, but with EOC-RPT trip capability maintained (refer to Required Action 8.1 Bases}, the EOG-RPT System is capable of performing the inter'lded function. However, the reliability and redundancy of the EOC-RPT instrumentation is reduced such that a single failure in the remaining trip system could result in the inability of the EOC-RPT System to perform the intended function. Therefore, only a. 1imi ted, time is allowed to restore compliance with the LCD. Because of the diversity of sensors available to provide trip signals, the Tow probabi,lity of extens1ve numbers of fnoperabilities affecti'ng all diverse Functions, and the low probability of an event requiring the initiation of an EOC~RPT, 72 hours is provided to restore the inoperable channels (Required Action A.1). Alternately, the inoperable channels may be placed in trip (Requfred Action A.2) sinc.e this would conservatively compensate for the inoperability, restore capabi:l i ty to accommodate, a single- fai 1ure, and allow operation to continu,e. As noted in Required Action A.2, placing the channel in trtp with no further restrictiqns is not allowed if the inoperable ehannel is the result of an inoperable breaker, since this may not adequately compensate for the inoperable breaker (e.g., the breaker may be inoperable such that it will not open). If it is not desired to place the channel in trip_ (e.g., as- in the case where placing the inoperable channel in trip would result in an RPT, or if the inoperable channel is the result of an inoperable breaker), Condition C must be entered and its Required Actions taken, Ll Required Action B.I is intended te e11sure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in the ~unction not maintaining EOC-RPT tri!} capability. A Function is considered to be maintaining EOC-RPT trip capability when sufficient channels are OPERABLE or i~ trip, s~ch that the EOC-RPT System will generate a t*rip signal from the given Function on a. valid signal and both recireulation pumps can be tripped. This requires two channels of the Function in the same trip system, to each he OPERABLE or in trip, and the associated EOC-RPT breakers to be OPERABLE .
* PBAPS UNIT 2                        B 3 ,,3-91f (continued)
Revision No, 57
 
EOC-RPT Instrumentation B 3.3.4.2
* BASES ACTIONS      Ll      (continued)
The 2 hour Completion Time is sufficient time for the operator to take torrective action, and takes into account the like1ihood of an event requiring actuation of the EOC-RPT instrumentation during this period. It i.s al so consistent with the 2 hour Completion Time provided in LCO 3.2.1 and 3.2.2 for Required Action A.1, since this instrumentation's purpose is to preclude a thermal limit vi.o l ati on.
C.1 and C.2 With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to< 26,3% RTP within 4 hours. Alternately, for an inoperable breaker (e.g., the breaker may be inoperable such that it will not open) the associated recirculation pump may be removed from service, si nee this performs the intended function of the.
instrumentation. The allowed Completion Time of 4 hours is reasonable, based on operating experi'ence, to reduce THERMAL POWER to< 26.3% RTP from full power conditions in an orderly manner and without challenging plant systems, Required Action C.1 is modified by a Note which states that the Required Action is only applicable if the inoperable channel is the result of an inoperable RPT breaker. The Note clarifies the situations under which the associated Required Action would be. the appropriate Required Action.
SURVEILLANCE The Surveillances are modifi.ed by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Survei1lances, entry into associated Conditions and Required Actions may be delayed for u,p to 6 hou,rs provided the associated Function maintains EOC-RPT trfp capability.. Upon completion of the Surveillance,. or expiration of the 6 hour a1lowance~ the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.. This Note is based on the reliability analysis (Ref. 5) assumption of the average time required to perform channe1 Surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the recirculation pumps will trip when necessary.
(continued)
* PBAPS UNIT 2                    B 3.3-91g                Revision No. 143
 
E0C-RPT Instrumentation B 3.3.4,2
* BASES
  -------------------------------~---
SURVEILLANCE  SR 3.3,4.2.1 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function.,
The Surveillance Frequency is controlled under the Survei 11 ance Frequency Control Program.
SR 3.3.4.2.2 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive c a 1i br a t i on s cons i st en t wtt h t he p1a nt s pe c if i c s et po 1n t methodology.
                !he Surveillance Frequency is controlled under the Surveillance Frequency Control Program .
* SR 3.3.4,2,3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the pump breakers is included as a part of this test, overlapping the LOG.IC SYSTEM FUNCTIONAL TEST, to provide complete testing of the associated safety function. Therefore, if a breaker is incapable of operating, the associated instrument channel Cs) would also be inoperable.
The Surveillance Frequency is controlled under the survei 11 ance F"requency Control Program .
* PBAPS UN IT 2                      B 3.3-9lh                                Revision No. 86
 
EOC-RPT Instrumentation B 3.3.4.2
* BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.4.2.4 This SR ensares that an EOC-RPI initiated from the TSV-Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is *~ 2'6. 3% RTP. This i nvo 1ves ca1 i brati on of the bypass channels. Adequate margins, for the instrument setpoint methodologies are incorporated into the actua1 setpoint. Because main turbine bypass flow can affect this setpoint nonconservatively (THERMAL POWER is derived from first stage pressure) the main turbine byP,ass valves must remain closed during the calibration at THERMAL POWER
                ~ 26.3% RTP to ensure that the calibration remains valid. If any bypass channel's setpoint is :nonconservative (i.e.~ the Furac:tions are bypassed at~ 26.3% RTP, either due to open main turbine bypass valves or other reasons), the affected TSV-Closure and TCV Fast Closure, Trip Oil Pressure-Low Functions are considered ,nope,rable. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met with the chanriel considered OPERABLE.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR 3.3,4.2.5 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The EOC-RPT SYSTEM RESPONSE TIME acceptance criterion is included in Reference 6.
A Note to the Survei 11 ance *states that breaker interruption time may be assumed from the. most recent performance of SR 3.3.4.2.6. Thi.s is allowed since the time to open the contacts after energization of the. trip coil and the arc suppression time are short and do not appreciably change, due to the design of the breaker opening device and the fact that the breaker is not routinely cycled.
(continued)
* PBAPS UNIT 2                      B 3.3-91i                    Revision No. 143
 
EOC-.RPT Instrumentation B 3~3.4.2
* BASES SURVEILLANCE REQUIREMENTS SR  3.3.4.2.5 (continued)
Response ti.mes cannot be deterrn1 ned at powe.r because operation of final actuated devices is required. The Survei1lance Frequency is controlled under the Surveillance Frequency Control Program .
              .SR 3:,3,4.2.6 This SR ensures that the RPT breaker interrupti"on time (arc suppression time plus time to open the contacts) is provided to the EOC-RPT SYSTEM RESPONSE TIME test. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program, REFERENCES    1. UFSAR, Figure 7.9.4A, Sheet 3 of 3 (EOC-RPT logic diagram).
2*    UFSAR, Section 7. 9. 4 ~ 4. 3 .
: 3. UFSAR, Section 14.5.1.2.4.
: 4. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fue1," latest approved version.
: 5. GENE-770-06-1-A, "Bases for Changes to Surveillance Test Intervals and Allowed Out-Of-Service Times for Selected Instrumentation Technical Specifications,"
December 1992.
: 6. Core Operating Limits Rep0rt.
: 7. NEDC-33873P, "Safety Analysis Report for Peach Bottom Atomic power Sation, Units 2 and 3, Thermal Power
                    . Opitimization," Revision O*
* PBAPS UNIT 2                    B 3,3-9lj                    Revision No. 143
 
ECCS Instrumentation B 3.3.5.1
* B 3.3 INSTRUMENTATION B 3.3.5.1 Emergency Core Cooling, System {ECCS) Instrumentation BASES BACKGROUND        The purpose of the ECCS instrUD1entation is to initiate appropriate responses from the systems to ensure that the fuel is adequately cooled in the event of a design basis accident or transient.
For most abnormal operational transients and Design Basis Acddents {DBAs), a wide range of dependent and independent parameters are monitored.
The ECCS instnJJRentation actuates core spray {CS), low pressure coolant injection {LPCI), high pressure coolant injection {HPCI), Automatic Depressurization System {.ADS),
and the diesel generators {DGs). The equipment involved with each of these systems is descrtbed in the Bases for LCO 3.5.1, ECCS-Opera:ting.
11              11
* Core Spray System The CS System may be initiated by automatic means.
Automatic initiafion occurs -for conditfons of Reactor Vessel
                    ~ater Level-Low Low Low {Level 1) or Drywel l Pressul'le-High with a Reactor Pressure-Low permissive. The reactor vessel water 1eve l and the reactor pressure. vari ab 1es are moni tared by four redundant transmitters, which are, in turn, connected to four pressure compensation instruments. The drywell pressure variable is 1110nitored by four redundant transmitters, which are, in turn, connected to four trip units. The outputs of the pressure compensation instruments and the trip units are connected to. relays which send sfgnals to two trip systems, with each trip system arranged in a one-out-of-two taken twice logic (each trip unit sends a signal to both trip systems.) Each trip system initiates two of the four CS pumps.
Upon receipt of an initiation signal, if normal AC power is available, CS pumps A and C start after a time delay of approximately 13 seconds and CS pumps Band D start after a time delay of approximately 23 seconds. If normal AC power is not available, the four CS pumps start simultaneously after a time delay of approximately 6 seconds after the respective DG, is ready to load *
* PBAPS UNIT 2                        B 3.3-92
                                                                        <continued}
Revision No. O
 
ECCS Instrumentation B 3.3.5.1
* BASES 8ACK 6ROUND  Core Spray System (continued)
The CS test line isolation valve, whic~ is also a primary containment isolation valve (PCIV), is closed on a CS initiation signal to allow full system flow assumed in the accident analyses and maintain p.rimary containment 1so1ated in the event CS is not Qpe.rat i ng.
The CS pump discharge flow is monitored by a differential pressure indicating switch. When the pump is running and discharge flow is low enough so that pump ove.rheating may occur, the minimum flow return line valve is opened. The valve is automatically closed 1f flow is above the minimum flow setpoint to allow the full system flow assumed in the accident analysis.
The CS System a1 so monitors the p.ressure in the reactor to ensure that, before the tnject ion va1 ves open, the reacto.r pressure has fallen to a value below the CS System's maximum design pressuT'e. The variable is IOOnitored by four redundant transmitters, which are, in turn, connected to four pressure* cOlnpensation instruments. The outputs of the
* pressure compensation instruments are connected to relays whose contacts are arranged in a one-aut-of-two taken twice logic.
Low Pressure Coolant In,iection System The LPCl is an operating mode of the Residual Heat Removal (RHR} System, with two LPCI subsystems. The LPCI subsystems may be inttiated by automatic means. - Automatic' initiation occurs f~r conditions of Reactor Vessel Water Level-Low Low Low (Level I); Drywell Pressure-High with a Reactor Pressure-Low (Injection Permissive). The drywell pressure variable is monitored by four redundant transmitters, which, in turn, are connected to four trip units. The reactor vessel water level and the reactor pressure variables are monitored by four redundant transmitters, which are, in turn, connected to four pressure compensation instrumehtS.
The outputs of the trip units and pressure compensation instruments are connected to relays which send signals to 1
two trip systems, with each trip system arranged in a one-out-of-two taken twice logic (each trip unit sends a signal to both trip systems). Each trip system can initiate all four LPCI pumps.                      *
{continued}
PBAPS UNIT 2                    B 3.3-93                      Revision No. 0
 
ECCS Instrumentation B 3.3.5.1
* BASES BACKGROUND  Low pressure Coolant ln,1ection System (cont"inued)
Upon receipt of an initiation signal if normal AC power is available, the LPCI A and B pumps start afteY' a delay of approximately 2 seconds. The LPCI C and D pumps are started after a delay of approximately 8 seconds. If normal AC power 1s not available, the four LPCI pumps start simoltaneously with no delay as soon as the standby power source is available.
Each LPCI subsystem's discharge f1 ow is monitoted by a differential pressure indicating switch. When a p&#xb5;mp is running and discharge flow is low enough so that pump overheating may occur, the respective minimum flow return line valve is opened.. If flow is above the minimum flow setpo1nt, the valve is automatically closed to allow the full system flow assumed in the analyses.
The RHR test line suppresston pool cooling isolation valve, suppression pool spray tsolation valves, andcontaihment spray isolation valves (which are also PCIVs) are also closed on a LPCl 1n:itiation signal to allow the full system flow assumed 1n the accident analyses and maintain primary containment isolated in the event LPCI ts not operating.
The LPC-J-Systelil monitors the pressure in the reactor to ensure that, before an injection valve opens, the reactor pressure has fallen to a value below the* LPCI System's maximum design pressure. The variable is monitored by four redundant transmitters, which are, in turn, connected to four pressure compensation instrLDDents. The outputs of the pressure compensation instrwnents are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic. Additionally, instruments are provided to close the.
recirculation pump discharge valves to ensure that LPCI flow does not bypass the core when it injects into the recirculation 1 ines. lhe variable is *monitored by four redundant transmitters, which are, in turn, connected to four pressure compensation instruments .. The outputs of the pressure .compensati'on instruments are connected to relays whose contacts are arranged in a one-out-of-two taken twice 1ogic.
                                                                    <continued}
* PBAPS UNIT 2                    B 3.3-94                      Revision No. 0
 
ECCS Instrumentation B 3.3.5.1
* BASES 8ACKGROUND  Low Pressure coolant Injection System    {continued)
Low reactor water level in the shroud is detected by two additional instruments. When the level is greater than the low level setpoint LPCI may no longer be required, therefore other modes of RHR {e.g., suppression pool cooling) are allowed. Manual overrides for the isolations below the low level setpoin.t are provided.
High Pressure  Coolant In.iection  System The HPCI System may be initiated by automatic means.
Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low low {Level 2) or Drywell Pressure-High.
The reactor vessel water level variable is monitored by four redundant transmitters, which are, in turn, connected to four pressure compensation instruments. The drywell pressure variable is monitored by four redundant transmitters, which are, in turn, connected to four trip units. The outputs of the pressure compensation instruments and the trip units are connected to relays whose contacts
* are arranged in a one-out-of-two taken twice logic for each Function.
The HPCI pump discharge f1ow is monitored by a flow switch.
When the pump is running and discharge flow is low enough so that pump overheating may occur, the minimum flow return line valve is opened. The valve is automatically closed if flow is above the IRinillUIII flow setpoint to allow the full system fl ow assumed in the safety ana1ys is.
The HPCI test line isolation valve {which is also a PCIV) is elosed upon receipt of a HPCI initiation signal to allow the full system flow assU1Red in the accident analysis and maintain primary containment isolated ,in the event HPCI is not operating.
The HPCI System also monitors the water levels in the condensate storage tank (CST) and the suppression pool because these are the two sources of water for HPCI operation.. Reactor grade water in the CST is the nonnal
              .source. Upon receipt of a HPCI initiation signal, the CST
{continued)
* PBAPS UNIT 2                    B 3.3-95                        Revision No. 0
 
ECCS Instrumentation
                                                                    .B 3 .3. 5 .1
* BASES BACKGROUND  High Pressure Coolant Injection System {continued) suet iOn valve is automatically signaled to open (it is        .
normally in the. open position} unless both suppression pool suction valves are open. If the water level in the CST falls below a preselected level, first the suppression pool suction valves automatically open, and then the CST suction valve automatically closes. Two level switches are used to detect low water level 1'n the CST. - Either switch can cause the suppression pool .suction valves to open and the CST suction valve to close. The suppression pool suction valves also automatically open and the CST suction valve closes if high water level is detected in the suppression pool. To prevent losing suction to the pump, the suction valves are interlocked so that one .suction path must be open before the other automatically closes.
The HPCI provides makeup water to the reactor until the reactor vessel water level reaches the Reactor Vessel Water Level-High (Level 8) trip, at which time the HPCI turbine trips, which causes the turbine's stop valve and the control valves to close. The logic is two-out-or-two to provide
* high reliability of the HPCI System. The HPCI System automatically restarts if a Reactor Vessel Water Level-Low Low (Level 2) signal is subsequently received.
Automatic Peoressurization System
                                                                    ~
The ADS raay be initiated by automatic means. Automatic initiation occurs when signals indicati.ng Reactor Vessel Water Level-Low Low Low (Le.vel 1); Drywall Pressu're-High or ADS Bypass Low Water te,vel Actuation Ti111er; Reactor Vesse1 Water Confirmatory Leve 1-Low ,( Level 4) ; and CS or LPCI Pump Discharge Pressure-High are all present and the ADS Inttiati:on Timer has timed out. There are two transmitters each for Reactor Vessel Water Level,.:__Low Low Low (Level 1) and Drywe11 Pressure-High, and one transmitter for Reactor V~ssel Water Confi.rmatory Level-Low (Level 4) in each of the two ADS trip systems*. Each of these transmitters connects to a trip unit, which then drives a relay whose contacts form the initiation logic.
Each ADS trip .system includes a time delay between satisfying the initiation logic and the actuation of the ADS valves. The ADS Initiation Timer time delay setpoint chosen is long enough that the HPCI has sufficient operating time
* PBAPS UNIT 2                  B 3.3-96 Ccontinuedl Revision No. 0
 
ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND  Automatic Depressurization System (continued}
to recover to a level above Level 1, yet not so long that
_the LPCI and CS Systems are unable to adequately cool the fuel if the HPCI fails to maintain that level. An alann in the control room ts annunciated when either of the timers is timing. Resetting the ADS initiation signals resets the ADS Initiation Timers~
The ADS also mn1tors the discharge pressures of the four LPCI pumps and the four CS pumps. Each ADS trip system includes two discharge pressure permissive switches from all four LPC1 pumps and one discharge pressure permissive switch from all four CS pumps. The signals are used as a permissive for ADS actuation, indicating that there is a sourc~ of core coolant available once the ADS has depressurized the vessel. Two CS pumps in proper combination (C or D and A or 8) or any one of the four LPCI pwnps is sufficient to pennit automatic depressurization.
The ADS logic in each trip system is arranged in two strings.* Each string has _a coniact from each of the following variables: Reactor Vessel Water Level-Low Low Low (Level 1); Drywell. Pressure-High; Low Water Level Actuation Timer; and Reactor Vessel Water Level -Low Low Low (level 1-) Pennissive.
* One of the-two strings*in each trip system must a1so have a Reactor Vesse 1 Water Conf-1,nnatory Level--.Low (Level 4). After the contacts for the initiation signal from either drywell pressure or reactor vessel 1evel (and the ttmer for reactor vessel level timing out) close, the following must be present to initiate an ADS trip system: all other contacts in both logic strings must close, the ADS initiation timer must time out, and a. CS or LPCI pump discharge pressure signal must be p.resent. Either the A or B trip system wi 11 cause a11 the 'ADS relief valves to open. Once the Drywell Pressure-High signal, the ADS Low Water Level Actuation Timer, or the ADS initiation signal is present, it is individually sealed in until manually reset.
Manual inhibit switches are provided in the control room for the ADS; however, their function is not required for ADS OPERABILITY (provided ADS is not inhibited when required to be OPERABLE)~
{cont1nued}
PBAPS UNIT 2                    8 3.3-97                      Revision No. O
 
ECCS Instrumentation 8 3.3.5.1 BASES BACKGROUND        Diesel Generators (cont1n1:1ed)
The DGs may be initiated by automatic means .. Automatic initiation occurs for conditions of Reactor Vessel Water Level-tow Low Low (Level 1) or Drywell Pressure-High. The DGs are also initiated upon loss of voltage signals. (Refer to the Bases for LCO 3.3.8.1, "Loss of Power (LOP)
Instrumentationj" for a discussion of these signals.) The reactor vessel water 1evel variable i*s monitored by four redundant transmitters, which are, in turn, connected to four pressure compensation instruments. The drywell pre,ssure variable is monitored by four red1:mdant transmitters, which are, in_turn, connected to four trip units. The outputs of the four pressure compensation instruments and the trip units are connected to relays which send signals to two trip systems, with each trip system arranged in a one-out-of-two taken twice logic (each trip unit sends a signal to both trip systems). The A trip system initiates all four DGs and the B trip system initiates all four DGs. The OGs receive their initiation signals from the CS System inithtion logic. The DGs can also be started manually from the control room and locally
* from the associated DG room. Upon receipt of a loss of coolant accident (lOCA) initiation signal, each DG is automatically started, is ready to load in approximately 10 seconds, and will run in standby conditions (rated volta~e and speed, with the DG output breaker open). The DGs will only energize their respective. Engineered Safety Feature buses if a loss of offsite power occurs. (Refer to Bases for LCO 3.3.8.1.)
APPLICABLE        The actions of the ECCS are explicitly assumed in the safety SAFETY ANALYSES,  analyses of References 1, 2, and 3. The ~CCS is initiated LCO, and        to preserve the integrity of the fuel cladding by limiting APPLICABILITY    the post LOCA peak cladding temperature to less than the 10 CFR 50.46 limits.
ECCS instrumentation satisfies Criterion 3 of the NRC Policy Statement. Certain instrumentation Funct1ons are retained for other reasons and are described below in tha indivfdua1 Functions discussion.
The OPERABILITY of the ECCS instrU111entation is dependent upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.5.1-1. Each Function must have a required number of OPERABLE channels,
                                                                          <continued)
I PBAPS UN IT 2                      B 3.3-98                    Rev i s ion No. 21
 
ECCS Instrumentation B 3.3.5.1
* BASES APPLICABLE SAFETY ANALYSES, LCO, and with their setpoints within the specified Allowable Values, where a.ppropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
APPLICABILITY    Table 3.3.5.1.-1 is modified by a footnote which is added to (continued)      show that certain ECCS instrumentation Furactions also perform DG initiation.
Allowable Values are specified for each ECCS Function specified in the Table. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure that the settings do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setting less conservative than the trip setpoint, but within it s A11 ow a b1e Va. l ue , i s a cc e pt a b1e . A ch a nne 1 i s i no pe r a bl e if its aetual trip setpoint is not within its required A1lowa,ble Value. Trip setpoints are. those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e .. g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The a na l y t i c o r de s i gn 1 i mit s a re de r i ved from t h,e 1 i mit i ng values of the process parameters obtained from the safety analysis or other appropriate documents. The Allowable Values are derived from the analytic or design limits, corrected for calibration, process. and ihstrumerat errors.
Jhe trip setpoints are determined from ana"lyti.cal or design
                  ~imits. corrected for calibration, process, and instrument errors, as well as, instrument drift. In selected cases, the Allowable Values and trip setpoints are determined from engineering judgement or historically accepted practice relative to the intended functions of the channel. The trip setpoints determined in this manner provide adequate protection by assuming instrument and process uncertainties expected for the environments during the operating time of the associated channel5, are accounted for. For the Core Spray and LPCI Pt:.!mp Start-Time Delay Relays, adequate margins for applicable setpoint methodologies are incorporated into the Allowable Values and actual setpoints.
In general, the individual Functions are required to be OPE~ABLE in the MODES or other specified conditions that may require ECCS (or DG) initiation to mitigate the consequences of a design basis transient or accident. To ensure reliable ECCS and DG function, a combination of Functions i~ required to provide primary and secondary initiation signals .
* PBAPS UNIT 2                                B 3.3-99                            Revision No. 145
 
ECCS Instrumentation B 3.3.5.1
* BASES
    --------------~--------------~~~----
APPLICABLE        The specific Applicable Safety Analyses, LCO, and SAFETY ANALYSES I Applicability discussions are listed below on a Function by LCO, ar:id        Function basis.
APPLICABILITY (continued) cor!; SQrav and Low Pressure Cool2nt Iniection Systems La. 2,a.      Reactor Vessel Water Level-Low Low Low CLeveJ l)
Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may De threatened. Should RPV water level decrease too far, fuel damage could result.
The low pressure &#xa3;CCS and associated DGs are initiated at Reactor Vessel Water Level - Low Low Low ( level 1) to ensure t hat co r e s pr' ay a nd fl oodi ng f unct i o ns a re a v a i 7 ab l e to prevent or minimize fuel damage. The DGs are initiated from Function l.a signals. This Function, in conjunction with a Reactor Pressure-Low (Injection Permissive) signal, also initiates the closure of the Recirculation Discharge Valves to ensure the LPCI subsystems inject into the proper RPV location. -The Reactor Vessel Water Level-Low Low Low (Level 1) is one of the Functiorrs assumed to be OPERABLE and
* capable of initiating the ECCS during the transients analyzed in References 1 and 3. In addition, the Reactor Vessel Water Level-Low Low Low (Level 1) function is directly ~ssumed in the an~lysis of the recirculation line break (Ref. 4) and the control rod drop accident CCRDA) analysis. The core c_ooling function of the ECCS, along with the scram action Of the Reactor Protection System CRPS),
ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Reactor Vessel Water Level-Low Low Low (Lev~l 1) signals are initiated from four level transmitters that sense the difference between the pressure due to a constant eolumn of
                      'water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.
The Reactor Vessel Water Level - Low Low Low (Levl 1)
Allowable Value is chosen to allow time for the low pressure core flooding systems to activate and provide adequate cooling.
Four channels of .Reactor Vessel Water Level ~Low Low Low (Level 1) Function are only required to be OPERABLE when the ECCS are requ,red to be OPERABLE to ensure that no single instrument failure can preclude ECCS initiation .
* PBAPS UN IT 2                            B 3.3-100                            Revision No. 145
 
ECCS Instrumentation B 3.3.5.1
* BASES APPLJCABLE SAHTY ANALYSES I LCD, and APPLICABILITY l.b. 2,b.      Drvwel1 Pressure-H1qh High pressure in the drywel l toul d indicate a break in the reactor coolant pressure boundary CRCPB). The low pressure ECCS and associated DGs are initiated upon receipt of the Drywell Pressure-High Function with a Reactor Pressure-Low (Injection Permissive) in order to minimize the possibility of fuel damage. The DGs are initiated from Function l.b s i gna l s . Th i s Fun ct i on al s o i n it i ate s t he. c l o.s ure of Ul e recircula.tion dis.charge valves to ensure the LPCl subsystems inject into the proper RPV location. The Drywell Pressu.re-High Function with a Reactor Pressure-Low (Injection Permissive), along with the Reactor Water Level-Low Low Low (Level 1) Function, is directly as.sumed in the analysis of the recirculation line break (Ref. 4).
The core cooling function of the ECCS, a1ong with the scram action of the RPS, ensures that the fuel peak cladding
* tempeNture remains below the limits of 10 CFR 50.46 .
High drywell pressure signals are initiated from four pressure tr.ansmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside primary co~tainment.
The D*rywe]l Pressure-High Function is required to be OPERABLE when the ECCS or DG is required to be OPERABLE in conjunction with times when the primary containment is required to be OPERABLE. Thus, four channels of the CS and LPCI Drywell Pressure-High FL.nction are required to be OPERABLE in MODES 1. 2, and 3 to ensure that no single instrument failure can preclude ECCS and DG initiation. In MODES 4 and 5, the Drywell Pressure-High Function is not require-0, since there is insufficient energy in the reactor to pressurize the primary containment to Drywell Pressure-High setpoint. Refer to LCO 3.5.1 for Applicability Bases for the low pressure ECCS subsystems and to LCO 3.8, 1 for Applicability Bases for the DGs .
* PBAPS lJNIT 2                          B 3.3-101                                Revis1on No. 145
 
ECCS Instrumentation B 3.3.5.1
* BASES APPLICABLE SAFETY ANALYSES, LCO, and 1.c, 2,c. Reactor Pressurelow Ciniection Permissive)
Low reactor pressure signals are used as permissives for the APPLIGABLLITY    tow pressure EGCS subsystems. This ensures that, prior tb (continued)    opening the injection valves of the 1ow pressure ECCS subsystems or initiating the low pressure ECCS subsystems on a Drywell Pressure-High signal, the reactor pressure has fallen to a value below these .subsystems' maximum design pressure and a break inside the RCPB has occurred respectively. This Function also provides permissive for the closure of the recirculation discharge valves to ensure the LPCI subsystems inJect into the proper RPV location.
The Reactor Pressure-Low is one of the Functions assumed to be OPERABLE and capable of permitting initiation of the ECCS during the transients analyzed in References 1 and 3. In addition, the Reactor Pressure-Low Function is directly assumed in the analysis of the recirculation line break (Ref. 4), The core cooling function of the ECCS, along with the scram acti~A of the RPS, ensures that the fuel peak dladding temperature remains below the limits of 10 CFR 50.46.
The Rea,ctor Pressure-Low signals are initiated from four pressure transmitters that sense the reactor dome pressure .
The Allowable Value i.s low enoU-gh to prevent overpressuring the equipment in the low pressure ECCS, but high enough to ensure that the ECCS injection prevents the fuel peak cladding temperature from exceeding the limits of 10 CFR 50.46 ..
Four channels of Reactor Pressure-Low Function are only required to be OPERABLE when the ECCS is required to be OPERABLE to ensure that no single instrument failure can preclude ECCS initiation.
l,d. 2.g. Core Spray and Low Pressure Coolant Injection Pump Discharge Flow-Low CBvpass2 The minimum flow instruments are provided to protect the associated low pressure ECCS pump from overheating when the pump is operating and the associated injection valve is not fully open. The minimum flow line valve is opened when low flow is sensed, and the valve is automatically closed when the flow rate is adequate to protect the pump. The LPCI and
* .PBAPS UN IT 2                      B 3. 3-102                  Revision No. 145
 
EC(S Instrumentation B 3.3.5.1
* BASES APPLICABLE SAFETY ANALYSES I LCD, and APPLICABILITY l.e, 1,f~
( cont i nuedJ Core Spray Pump Start-Time Delay Relay There are eight Core, Spray P.ump Start-Time DeJay Relays, two in each of the CS pump stBrt logic Circuits (one for when offsite power is available and one for when offstte power is not available). One of each type of time delay relay is dedicated to a single pump start logic, suth that a single failure of a Core Spray Pump Start-Time Delay Relay will not result tn the failure of more than one CS pu~p. In this condition, three of the four CS pumps will remain OPERABLE; thus, the s*ingle failure criterion is met (i.e.,
loss of one instrument does not preclude ECCS inttiation).
The Allowable Value for the Core Spray Pump Start-Time Delay Relays is chosen to be long enough sa that the power source will not be overloaded and short enough so that ECCS operation is not degraded.
Each channel of Core Spray Pump Start~Time Delay Relay Function is required to be OPERABLE only when the associated CS subsystem ts required to be OPERABlE.
2,d. Reactor rressure:;-L0w ~ow (Recirculation Discharge Valve Permissive)
Low reactor pressure signals are used as permissives for recircu1ation discharge valve closure. This ensures that t~e LPCI subsystems inject into the proper RPV locat~on ass*umed in the safety analysis. The Reactor Pressure-Low Low is one of the Functions a;ssumed to be OPERABLE and capable of closing the val~e during the transients analyzed in References 1 and 3. The, core co.o1 i 119 functton of the ECCS, along wi tfi the scram action of the RPS, e.nsures that the fuel peak claddil:1g temperature remains below the limHs of 10 CFR 50.46. The Reactor Pressure-Low Low FlJnction is directly assumed in the analysis of the recirculation line break (Ref. 4).
The Re.actor Pressure~Low Low signals are initiated from four presS'ure transmitters that sense the reactor pressure.
The Allowable Value is c~osen to ~nsu~e that the valves close prior to commencement of LPCI injection flow into the core, as assumed in the safety analysis .
* PBAPS UN IT 2                          B 3.3-104                    Revision No. 145
 
ECCS Instrumentation B 3.3.S.l
* BASES APPLICABLE SAFETY ANALYSES, Leo, and 2.d. Reactor Pressure-Low; Low {Recirculation Discharge Valve Pennissive) (continued)
APPLICABILITY . Four channels of the Reactor Pressure-Low Low Function are only required to be OPERABLE 1n MODES 1, 2, and 3 with the associated ~ecirculation pUllp discharge valve open. With the valve.(s) closed, the function of the instrumentation h~s been perfonned; thus" the Function is not required. In .
MODES 4 and 5, tha loop injection location is not critical since LPCI injection through the re"Circulation loop in either direction will still ensure that LPCI flow reaches the core (i.e., there ts no significant reactor back pressure).
2.e. Reactor Vessel Shroud Level-Level      o The Reactor Yesse l Shroud Level -Level O Function is 1
provided as a permissive to allow the RHR System to be manually aligned from the LPCI mode to the suppression pool cooling/spra,y or drywell spray modes. The reactor vessel shroud level permissive ensures that water in the vessel 1s approxi.mately two thirds core height befo.re the manual transfer is allowed. This ensures that LPCl is ava.ilable to prevent or minimize fuel damage. This function may be.
overridden during accident conditions as allowed by pl.ant procedures. -Reactor Vessel Shroud Level-Level O Function is implicitly assumed in the *analysis of the recirculation line break (Ref. 4) since the analysis as*sumes that no LPCI fl ow divers ion occu.rs when reactor water l eve 1 i. s be 1ow Level 0.
Reactor Vessel Shroud Level-Level O si.gnal s are ini.ti ated frDRl two level transmitters that sense the difference
                    .between the pressute due to a constant column of water (refe.rence leg) and the pressure due to the actual water level (variable leg) in the vessel. The Reactor Vessel Shroud Level-Level O Allowable Value is chosen to all ow the low pressure core flooding systems to activite and provide.
                    .adequate cooliqg befQre allowing a 91anual transfer.
(continued)
PBAPS UNIT 2                        B 3.3-105                        Revision No. o
 
ECCS Instrumentation B 3.3.5.l
* BASES
  ------~~-~-----------------'--~-----~
APPLICABLE      2, e,  Reas;tor Vessel Shrou,d level-Level      o  (continued)
SAFETY ANALYSES, LCO, and        Two channels of the Reactor Vessel Shroud Level - Level 0 APPUCABI LITY    Function are only required to be OPERABLE in MODES 1, 2, and 3. In MODES 4 and 5, the specified initiation time of the LPCI subsystems is not ass.urned, and other administrat1ve controls are adequate to control the valves associated with Uii s Funct.i on Cs i nee the systems that the va 1 ves a re opened for are not required to be OPERABLE in MODES 4 and 5 and are no,rmall y not used}.
2,f. Low Pressure Coolant Jniectioe Pump Start-Time Pelav
                  ~
The purpose of this time delay is to stagger the start of the LPCI pumps that are in each of Divisio:ns I and II, to prevent overloading the power source. This Function is only necessary when power is being supplied from offsite sources.
The LPCI pumps start simultaneously with no time de1ay as soon as the standby source is available. The LPCI Pump Start-Time Delay Re1ayt are assumed to be OPERABLE in the accident and transient analyses requiring ECCS initiation.
That is, the analyses assume that the pumps will initiate
* when required and excess loading Will aot cause failure of the power sources.
There- a-re ei gh:t L'PCI Pump Start..:.. Ti me Delay Rel-ays, two i rr each of the RHR pump start logic circuits. Two time delay relays are dedicated to a siagle pump start logic. Both timers in the RHR pump start logic would have to fail to
                  ~revent an RHR pump from starting within the required time; therefore, the low pressure ECCS pumps will remain OPERABLE; thus 1 the singJe failure criterion is met (i.e., Toss of one instrument does nDt preclude ECCS initiation). The Allowable Values for the LPCI Pump Start-Time Delay Relays are chose~ to be long enough so that most of the starting transient 0if the first pump is complete bf<fore startirig the second pump on the same 4 kV emergency bus and short enough so that ECCS operation is not degrad~d-Each channel of LPCI !?'ump $tart-Time Delay Relay Function is required to be OPERABLE only when the associated LPCI subsystem is required to be OPERABLE .
* P13APS UNIT 2                          B 3.3-106                        Revision No. 145
 
ECCS InstrumentatiQn B 3.3.S.1
* BASES APPLICABLE SAFETY ANALYSES, LCO, and High Pressure Cool ant InJection CHPCI} System 3.a. Reactor Vessel Water level-Low Low {Level 2)
APPLICABILITY (cont tnued)    Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease
                  . too far, fuel' damage could result. Therefore, the HPCI System is initiated at Level 2 to maintain level above the top of the active fuel. The Reactor Vessel Water Level-Low Low (Level 2) is one of the Functions assumed to be OPERABLE and capable of initiating HPCI during the transients anal yted in References l and 3. Addi ti ona11 y, the Reacto.r Vessel Water Level-Low Low (Level 2) Function associated with HPCI is credited as a backup to the Drywell Pressure-High Function for initiating HPCI in the analysis of the recirculation line break. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46~
Reactor Vessel Water Level-Low Low (Level 2.) signals are initiated from four level transmitte.rs that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.
The Reactor Vessel Water Level-Low Low (Level 2) Allowable Value is high enough such that for complete loss of feedwater flow, the Reactor Core Isolation Cooling (RCIC)
System flow with HPCI assumed to fail will be sufficient to avoid initiation of low pressure ECCS at Reactor Vessel Water Level-Low low Low (Level 1).
Four channels of Reactor Vessel Water Level-Low Low (level 2) Function are required to be OPERABLE only when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI initiation. Refer to LCO 3.5.1 for HPCI Appltcability Bases.
: 3. b. Drywel] Pressure-High High pressure in the drywell could indicate a break tn the RCPB. The HPCI System is initiated upon receipt of the Drywell Pressure-High Function in order to minimize the poss1bil ity of fuel damage. The Drywell Pressure-High Function is directly assumed"in the analysis of the (continued)
PBAPS UNIT 2                        B 3.3-107                      Revision No. O
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE          3,.b. PrvweJJ        Ptessure---High (continued)
SAFETY ANALYSES, tco, and            recirculation line break (Ref. 4). The core cooling APPLICABILITY        function of the ECCS, along with the scram action ,of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.                        ,
High drywell pressure signals are initiated from four pressure trans.itters that sense dr,vwen pressure. The Allowabl,e Value was selected to be as low as poss1ble to be indicative of a LOCA inside primary containment.
Four channels of the Drywell Pressure-High Function are                      _
required to be OPERABLE when HPCl is required to be OPERABLE to ensure that no single tnstrumeht failure can preclude HPCI initiation. Refer to LCO 3.5.1 f'or the AJ)plicability Bases for the HPCI system,.
3,c. Reactor Vessel Water Level-High CteveJ 81 High RPV water level indicates that sufficient cooling water
                                      *1nventory exists in the reactor vessel such that there is no danger to the fuel. Therefore, the Level 8 signal is used to trip the HPCI turbine to prevent overflow into the ma:in steam lines (MSLs). The Reactor Vessel Water level-High
- -- --.-----.c- - --- - -- --- --~ -- -( Level--8 )--f.unc-t-1 on -1 s-assumed-to-tr1,p- the-HPC1--turbtn*e~;-n- -- ~ -- ~
the feedwater controller failure transient analysis if HPCI is initiated.
* Reactor Vessel Water Level-High (Level 8) signals for HPCI are initiated from two level transmitters from the wide range water level 11easurentent instrumentation. Both Level 8 signals are required in order' to trip the HPCI turbine.
This ensures that no single i,nstruaent failure c"n preclude l1PCI initiation. The Reactor Vessel Water Level-High (Level 8) Allowable Value is chosen to prevent flow from the HPCI System from overflowing into the MSLs.
Two channels of Reactor Vessel Water Level-High (Level 8)
Function are *required to be OPERABLE only when HPCI is required to be OPERABLE. Refer to LCO 3.5.l and LCO 3.5.2 for HPCI Applicability Bases.
{continued}
PBAPS UNIT 2                                  B 3.3,-108                        Revision No~ 0
 
ECCS Instrumentation B 3.3.5.l BASES APPLICABLE        3,d. Condensate Storage Tank Level-Low SAFETY ANALYSES, LCO, and          Low level i.n the CST indicates the unavailability of an.
APPLICABILITY      adequate supply of makeup water from this normal source.
(continued)    Normally the suction valves between HPCI and the CST are open and, upon receiving a HPCI initiation sig,nal, water for HPCI injection would be taken from the CST. Howe.var, if the water level 1n the CST falls below a preselected level, first the suppression pool suction valves automatically open, and then the CST suction valve automatically closes.
This ensures that an adequate supply of makeup water is available to the HPCI pump. To prevent losing suction to the pump, the suction valves are interlocked so that the ..
suppression pool suction valves A1Ust be open before the CST suction valve automatically closes. The Function is implicitly assumed in the accident and transient analyses (which take credit for HPCI) since the analyses assume that the HPCI suction source. 1s the suppression pool'.
Condensate Storage Tank Level-Low signals are initiated from two level switches. The logic is arranged such that either level switch can cause the suppression pool suction valves to open and the CST sucti,on valve to close. The lj                    Condensate Storage Tank Level-Low Function Allowable Value 1s high enough to ensure adequate pump suction head while
                    *-water* is being taken-from.-the-C---5T. - **--- --*-*-* **---- -- * ~-
Two channels of the Condensate Storage Tank Level-Low Function are required to be, OPERABLE only when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI swap to suppres.sion pool source.
Refer to LCO 3 *. 5.l for HPCI Applicability Bases.
3,e. suopressjon Pool Water Level-High Excessively high suppression pool water could result in the loads on the suppression pool exceeding design values should there be a blowdQWfl of the reactor vessel pressure through the safety/relief valves. Therefore, Signals indicating high suppression pool water level are used to transfer the suction source of HPCI from the* CST to the suppression pool to .eliminate, the possibfl1ty of HPCI continuing to provide additional water fr0111 a source outside containment. To prevent losing suction to the pump, the suction valves are interlocked so that the suppression poo.l suet ion va1ves must be open before the CST suction valve automatically closes.
lcontjnued)
PBAPS UNIT 2                          B 3.3-109                          Revision No. 0
 
ECCS Instrumentation B 3.3.5.l BASES APPLICABLE        3,e, Suppression Pool Water Leyel-f:fiqh_ {conttnued)
SAFETY ANALYSES, LCO, and          This Function is implicitly assUJDed 1n the accident and APPLICABILITY      transient analyses (which take credit for HPCI} since the analyses asslllie that the HPC I .suet ion source is the suppression pool.
Suppression Pool' Water Level-High signals are initiated from two level switches. The logic is ar,ranged such that e.ither switch can cause the suppression pool suction valves to open. and the CST suction valve to close. The Allowable Value for the .Suppression Pool Water Level-High Function is chosen to ensure that HPCI wil'l be aligned for suction from the supf)t-ession pool to prevent.HPCI from contributing to any further tncrease in the suppressHm pool level.
Two channels of Suppression Pool Water Level-High F'Unction are required to be OPERABLE only when HPCI is required to be OPERABLE to ensure that no si.ngle instrument failure can preclude HPCI swap to suppression pool source. Refer to LCO 3.5.l for HPCI Applicability Bases.
3.f. High Pressure Coolant Injection Pump Discharge Fl ow-LQw f'Bypass l
                    -The -minimum* flow- instrument i.s provided to protect *the HPC-1 pump frora overheating when the PUIIJP is operating at reduced flow. The 11ini111UD1 flow line valve is opened when low flow is sensed, and the valve is automatically,closed when the flow rate is adequate to protect the pump. The High Pressure Cool ant Injection Pump 'Discharge Fl ow-Low Funct ton ts assumed to be. OPERABLE and capable of closing the minimum flow valve to ensure that the ECCS flow assumed during the transients analyzed in Reference 4 ts met. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the li~its of 10 CFR 50.46.
One fl ow switch ; s used to detect the' HP.CI System's fl ow rate. The logic is arranged such that the transmitter
                    ,causes the minimum flow valve to open. The logic will close the 111inimum flow valve once the closure setpo,int is exceeded.                                        -
Ccontinuedl
* -PBAPS UNiT 2                          B 3~3-110                      Revision No.' 0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE          3,f. High Pressure Coolant Iniect1on Pump Discharge SAFETY ANALYSES,    Flow-Low <Bypass) (continued) lCO, and APPLICABILITY      The High Pressure Coolant Injection Pump Discharge Flow~Low Allowable Value is high enough to ensure that pump flow rate is sufficient to protect the pump, yet low enough to ensure that the closure of the mintmum flow valve 1s inittated to allow full flow ioto the core.
One channel is requi,red to be OPERABLE when the HPCI is required to be OPERABLE. Refer to LCO 3.5.1 for HPCI Applicability Bases.
Automatic Depressurization System 4.a. 5.a, Reactor Vessel Water Level-Low Low Low (Level 1)
Low RPV water level indicates tha,t the capability to cool the fuel may be threatened. Should RPV water level decrease too far. fuel damage could result. Therefore, AO:S receives
* one of the signals necessary for initiation from this Function. This signal actuates the Fi:.mction 4.h, 5.h timer.
The Reactor Vessel Water Level -Low Low Low ( Level 1) is one
                    -- o-f the Fu-ncfi ons- a-ss-umed -to-be--OP{RABLT-and -ca-p-ab fe --o-f --
i ni ti ati ng the ADS during the accident analyzed in Reference 4. The core cooling function of the ECCS, along with the scram action of the RPSj ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Reactor Vessel Water Level - Low Low Low ( Level 1) signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure dae to the actual wate_r level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level ~Low Low Low (Level 1) Function are required to be OPERABLE only when ADS is required to be.
OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two channels input to ADS trip system A, whi1e the othe,r two channels input to ADS trip system B. Refer to LCD 3.5.1 for ADS Applicability Bases.
The R*eactor Vessel Water Level - Low Low Low ( Level 1)
Allowable Value is chosen to allow time for the low pressure core flooding systems. to initiate and provide adequate cooling .
PBAPS UNIT 2                            B 3.3-111                        Revision No. 78
 
ECCS Instrumentation B 3 .. 3. 5 .1
* BASES APPLICABLE SAFITY ANALYSES, LCO, and 4,b, 5,b. Drvwell Pressure-High High pressure in the drywell cou1d ihdicate a break in the APPLICABILITY    RCPB. Therefore, ADS receives one of the signals necessary (contir:iued)  for initiation from this Function in order :to 11inimize the possibility of fuel damage. The Drywell Pressu.re-ffigh is assumed to be OPERABLE and capable of initiating the ADS duri'ng the accidents analyzed in Reference 4. The C!Jre coo1ing function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature re111ains below the limits of 10 CFR S0.46.
Drywell Pressure-High signals are initiated from four press*ure transmitters that sense drywe 11 pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside pri.mary containment~
Four channels of Drywen Pressure-High Function are only required to be OPERABLE when ADS is required to be OPERABLE to ensure that no single. instrument failure can preclude ADS ihitiatfon.. Two channels input to ADS trip system A, while the other two channels input to ADS trip system B. Ref~r to LCO 3.5.1 for ADS Applicability Bases.              .
4:,c, 5,c, Automatic Depressuri,zation System Initiation 1imer*    - *- - -- * --~- - *-- -*- --~--- -- * ** - ----- -----~-
                                    ~                                                        ~  ~-*- -
The purpose of the Aut()lllat i c Depressuri zat i,on System Ini.ttation Timer is to delay depressuriz.ation of the reactor vessel to allow the HPCI System time to maintain reactor vessel water level. Since the rapid depressurization caused by ADS operation is one of the most severe transients on the reactor vessel, its occurrence should be limited. By delaying initiation of the A()S Function, the operator is given the, chance to 111011.itor the success or failure of the HPCI System to maintain water level, and then to decide whether or not to allow ADS to initiate, to delay initiation further by recycling the timer, or to inhibit in1tiation permanently. The Automatic. Depressurtzation. System Initiation Ti,er Function is as*sumed to be OPERABLE for the accident analysis of Reference 4 that requires ECCS initiation and assumes failure of the HPCI System.
{continued}
PBAPS UNIT 2                        B 3.3-112                              Revision No. 0
\
 
ECCS Instrumentation B 3.3.5.1.
* BASES
  .APPLICABLE SAFETY ANALYSES, LCO, and 4,c, s.c. Automatic Depressurization System Initiation Tjmer (continued)
APPLICABILITY    There are two Automatic Depressurization System Initiation Timer relays, one in each of the two ADS trip systems. The Allowable Value for the Automatic Depressuri:zation System Initiation Timer is chosen so that there is still time after depressurization for the low pressure ECCS subsystems to provide adequate core cooling.
Two channels of the Automatic Depressutization System Initiation Till8r Function.are only required to be OPERABLE when the ADS 1s required to be OPERABLE to ensure that m>
single 1nstrU11ent failure can preclude ADS initiation'" {One channel inputs to ADS trip system A, while the other channel inputs to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases~
4.d, 5,d, Reactor      Vessel Water Level- Low Low Low cLevel  ll {Penni ssj ve)
Low reactor water level signals are used as peT'11lissives in the ADS trip systems. This ensures after a high drywell pressure signal or a low reactor water level signal (Level 1) is received and the timer times out that a low reactor-water level~-flevel 1-), signal-*is present to--al1ow---
the .ADS in1tiat1on (after a confinnatory Level 4 signal, see Bases for Functions 4.e, 5.e, Reactor Vessel Water Confinnatory Level-Low (Level 4).
Reactor Vessel Water Level-Low Low Low (Level 1), signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure doe to the actual water level (variable leg) in the vessel. The Reactor Vessel Water Level-Low Low Low (Level 1) Allowable Value is chosen to allow time for the low pressure core flooding system to initiate and provide adequate cooling.
Four channels of the Reactor Vessel Water Level-Low Low Low
{Level l) Function are required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two. channels input to ADS trip system A while the other two channels input to ADS trip system B. Refer to LCO 3. 5.1 for ADS App11 cabil i ty Bases.
(continued)
* PBAPS UNIT 2                        B 3.3-113                    Revision No. 0
 
ECCS lnstrumentat ion B 3.3~5.l BASES APPLICABLE          4.e, s.e, Reactor Vessel water confinnatorv Level-Low SAFETY ANALYSES, {Level 4)
LCO, and APPLICABILITY        The Reactor Vessel Water Confirmatory Level-Low (Level 4)
(continued}      Function is used by the ADS pnly as a confirmatory low water level signal. ADS receives one of the signals necessary for tnitiation fro111 Reactor Vessel Water level-Low Low Low (Level 1) signals. In order to preveht spurious initiation of -the ADS due to spurious Level 1 signals, a Level 4 signal lflUSt also be received before ADS initiation cOll'lllences.
Reactor Vessel Water Confirmatory Level-Low (level 4) signals are initiated from two level transmitters that sense the difference between the pressure due to a constant column of water (reference. leg) and the pressure due to the actual water level (variable leg) in the vessel. lhe Allowable Value for Reactor Vessel Water Confinnatory Level -Low ..
(Level 4) is selected to be above the RPS Level 3 scram Allowable Value for convenience.
Two channels of Reactor Vessel Water Confirmatory Level-Low
{Level 4) Function are*only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude. ADS initiation. One channel inputs to ADS trip system A, whi.le the other channel inputs
    * - -- -- - - - --t-o-:ADS- trip -system -e..~--Refer -to- LC--0 3~ 5;l -for-ACS- -- -- ~ -
App1icability Bases.
4.f, 4.g,    5.f, 5.g, tore Spray and Low pressure coolant In,iectjon Pump Discha.rge Pressure-High The Pump Discharge Pressure-High signals from the CS .and LPCI pumps are used as permissives for ADS initiation, indicating that there is a source of low pressure cooling water available once the ADS has- depressurtzed the vessel,.
Pump Discharge Pressure-High is one of the Functions assumed to be OPERABLE and capable of pennitttng ADS initiation during the. events analyzed in Reference 4 with an assumed HPCI failure. for thes1! events the ADS depressurizes the reactor vessel so that the low pressure ECCS can perform_ the core cooling functions. This core cooling function of the ECCS, along with the scram action of the RPS., ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
(continued}
* PBAPS UNIT 2                              B 3 .3-114                            Revision No. 0
 
                                                              ~CCS Instrumentation B 3.3.5.1 BASES APPLICABLE        4,f, 4.g, 5,f, 5.g. Core Spray and Low Pressur~ Coolant SAFETY ANALYSES,,  Injection Pump Discharge Pressure-High (continued)
LCO, and APPLICABILITY    Pump discharge pressure si,gnals are initiated from twelve pressure transmitters, two on the discharge side of each of the four LPCI pumps and one on the discharge side of each CS PlllllP* There are two ADS low pressure. ECCS pump permissives in each trtp system. Each of the. permissives receives inputs from all four LPCI pumps (different .s.ignals for each per11issive) and two CS pumps, one from each subsystem (different pumps for each pennissive). In order to generate an ADS pera,issive in one trip system, it is necessary that only one LPCI pump or two CS pumps in proper combination (C or D and A or B) indicate the high discharge pressure condition in each of the two permissives. The Pump Discharge Pressure-High Allowable Value is less than the pump discharge pressure when the pump is operating in a full flow mode and high enough to avoid any condition that results 1n a discharge pressure permissive when the CS and LPCI pumps are aligned for injection and the pumps are not running. The actual operating point of this function is not assumed. in any transient or accident analysis. However, this Furiction is indirectly assumed to ope.rate (in Reference i                  4) to provide the ADS per'llissive to depressurize the RCS to allow the ECCS low pressure systems to operate.
Twelve channels of Core Spray and Low Pressure Coolant Injecti.on Pump Discharge Pressure-High Function are only required to be OPERABLE.when the ADS is required to be OPERABLE to ensure that no single instru111ent failure can preclude ADS initiation. Four CS channels associated with CS pumps A through D and eight LPCI channels associated with LPCI pumps A through Dare required for both trip systems.
Refer to LCO 3.5.1 for ADS Applicability Bases.
4,h, 5,h. Automatic    Depressurization  System Low Water  level Actuation Timer One of the signals required for ADS initiation is Orywell Pressure-Migh. However, if the event requiring ADS initiation occurs outside the drywell (e.g., main steam line break outside containment), a high drywell pressure stgnal
                    ~ay never be present. Therefore, the Automatic Depressurization Syste11 Low Water Level Actuation Timer is used to bypass the Drywe.11 Pressure-High Function after a (continued)
PBAPS UNIT 2                        B 3.3-115                      Revision No. 0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE      4.h, 5.h, Automatic Peores.surization system Low Water Level SAFETY ANALYSES, Actuation Timer (continued)
LCO, and APPLICABILITY    certain time peri,od has elapsed. Operation of the Automatic Depressurization System Low Water Level Actuation Timer Function is assumed in the accident analysis of Reference 4 that requires ECCS initiation and assumes failure of the HPCI system *.
There are four Automatic Depressurization System Low Water Level Actuation Timer relays, two in each of the two ADS trip systems. The Allowable Value for the Automatic Depressurization System Low Water Level Actuation Timer is chosen to ensure that there is still time .after depressurization for the low pressure ECCS subsystems to provide adequate core cooling.
Four channels of the Automatic Depressurization System Low Water Level Actuation Timer Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrWtent failure can preclude ADS initiation *. Refer to LCO 3.5.1 for ADS Applicability Bases *
* ACTIONS          A Note has been provided to modify the ACTIONS related to
                  -Eccs-i nstruraentat ron- -channe1s .- --sectlon ,-. r, Completion" - - -
Times, specifies that once a Condition has been ente.red, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable ECCS 1'nstrUJ11entat ion channe1s provide app.ropri ate compensatory measures for separate inoperable Condition entry for each inoperable ECCS instrumentation channel.
A.:..l.
Required Action A.l directs entry into the appropriate Condition referenced in Table 3.3.5.1-1. The applicable Condition referenced in the table is Function dependent.
Each time a channel is discovered inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition *
* PBAPS UNIT 2                        B 3.3-116
{continued}
Revision No. 0
 
ECCS Instrumentation B 3.3.5.1 BASES ACTIONS      B.1, B.2. and B.3 (continued)
Requfred Actions 8.1 and B.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untr,ipped charmel s within the same Function result in redundant automatic initiation capability being lost for the feature(s). Required Action B.l features would be those that are initiated by Functions l.a, 1.b, 2,a1 and 2.b Ce.g,, low pressure ECCS}. The Required Action B.2 system would be HPCL For Required Action 8.1, redundant automatic initiatton capability is lost if Cal two or more Function 1.a channels are inoperable and untripped such that both trip systems lose initiation capability, Cb) two or more Function 2.a channels are inoperable and untripped such that both trip systems lose initiation capability, (cl two or more Function 1.b -ct1annels are i.noperable and untripp.ed such that both trip systems lose initiation capability, or Cd) two or more Ft:1J1ction 2.b channels are inoperable and untripped such that both trip systems los~ initiation capability. For low pressure ECCS, since each inoperabl~
channel would have Required Actton B.l applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associate~ system of low pressure ECCS and DGs to be declared inoperable. However, si.oce ch_annel s in b.oth associated, l 0w- pressure EC0S
* subsystems (e.g., both CS subsystems) are jnoperable and untripped, and the Completio,i:1 Times started corl'currently for the channels in both subsystems, this results in the affected portions in the. associated low pressure ~CCS an-d DGs be i ng con c-u r r 1zn t l y dec l a red i nope r ab1 e .
For Requited Action B.2, redundant automatic HPCI initiation ca~ability is lost if two or more Function 3.a or two F~nction 3.b channels are inoperable and untripped such that the trip system loss initiation capability. In this situation Closs of redundant automat,c initiation capability), the 24 hour allowance of Required Action 8.3 is not appropriate and the HPCI System must be declared inoperable within 1 hour .
* PBAPS UN IT 2                        8 3.3-117                              Revision No. 145
 
ECCS Instrumentation B 3.3.5.1
* BAS.ES ACTIONS      8.1. 8.2. and B,3      (continued)
Notes are also provided (the Note to Required Action B.l and the Note to Required Action B.2) to delineate which Requir,ed Action is applicable for each Function that requ.ires entry into Condition B if an associated channel is inoperable.
This ensures that the proper loss 0f initiation capability check is performed. Required Action B.l (tbe Required Action for certain inoperable channe~s in the low prefsure ECCS subsystems) is not applicabre to Function 2.e, since this Function provides backup to administrative controls ensuring that operators do not divert LPCI flow from injectinf! into the core when nee.ded. Thus, a total loss of Function 2.e capability for 24 hours is a11owed, since the LPC I s ubsy sterns_ remain capable of pe.rformi ng their i nte.nd ed function.
The Complet1cn Time is intended to allow the operator time to evalLJate ahd repair any discovered inoper~bilities. This Completion Time also allows for an exception to the normal
*              "time zero" for beginning the allowed outage time "clock,"
For Required Action B.l, the Completion Time only begins
              ~9fl p_i:;cover'y that _a_ redundant feature-in -the- S-arne. sy-st-em (e.g., both CS s~bsystems) cannot be automatically initiated due to inoperable, untrippect channels within the same Function as described in the para~raph above. For Required Action B.2. the Completion Time only begins upon discovery that the HPCI System cannot be automatically inHiated du(=
to two inoperable, untripped channels for the. associated Functfon i11 the s2me trip s.ystern. The I hqur Completion Time from discovery of ioss of inHiation ca.pability is acceptable because it min~mizes risk while allowing time for restoration or tripping of channels.
Because of the-diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within tne
* PBAPS UNIT 2                      B 3.3-118                    Revi si<Hl No. 145
 
ECCS Instrumentation B 3.3.5.1
* BASES ACTIONS      8.1, 8,2, and B,3 (continued) allowable out of service time, the channel must be placed in the tripped condition per Required Action B~l. Placing the inoperable channel in trip would conservatively compensate for the i noperabil i ty, restore capability to accommodate a single failure, and allow operation to continue.
Alternately, if it is npt desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition H must be entered and its Required Action taken.
C.I and C.2 Required Action C.l is intended to ensure that appropriate actions are taken if multiple, inoperable channels within the same Function result in redundant automatic initiation capab:ility being lost for the feature(s). Required Action C.l features would be those that are initiated by Functions Le, l.e, l.f, 2.c, 2.d,. and 2.f (i.e., low pressure ECCS). Redundant automatic initiation capability is lost if either (a) two or more Function Le channels are inoperable in the same trip system such that the trip .system loses initiation capability, (b) two or 110re. Function l.e channels"'"are--inoperable-affecting cs- pumps-in-different- -- ---- -
subsystems, (c) two or 1ROre Function l.f channels are inoperable affecting CS pumps in different subsystems, {d) two or more Function 2.c channels are inoperable in the same trip system such that the trip system loses initiation capability, (e) t~o or more Function 2.d channels are inoperable in the same trip system such that the trip system loses initiation capability, or (f) three or more Function 2.f channels are inoperable. In this situation (loss of redundant automatic initiation capability), the 24 hour allowance of Required Action C.2 is not appropriate and the feature(s) associated with the inoperable channels must be declared inoperable within I hour. Since each inoperable channel wou1d have Required Action C.l applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated system to be declared inoperable. However, since channels for both low pressure ECCS subsystems are inoperable (e.g.,
both CS subsystems), and the Completion Times started concurrently for the channels in both subsystems, this results in the affected port.ions in both subsystems being (continued}
PBAPS UNIT 2                  B 3 .3-119                    Revision No. 0
 
ECCS Instrumentation B 3.3.5.I
* BASES ACTIONS      C.l and C,2 (continued) concurrently declared inoperable. For Functions l,c, 1.e, 1.f, 2.c, 2.d, and 2.f, the affected portions are the associated low pressure ECCS pumps.
The Note states that Required Action C.1 is only applicable for Functions l.c, l.e, 1.f, 2.c, 2.d, and 2.f, Required Action C.l 1s not applicable to Function 3.c (which also requ:i res entry into this Condi ti on if a channel in this Function is inoperable), since the loss of one channel results in a 1oss of the Function (two-out-of-two logic).
This loss was considered during the development of Reference 5 and considered acceptable for the 24 hours allowed by Required Action C.2.
The Completion Time 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 beginnjng the allowed outage time "clock."
For Required Action C.l, the Completion Time Qnly begins
* upon discovery that the same feature 1n both subsystems (e.g., both CS subsystems) cannot be automatically initiated due-to inoperable channe-1-s-wit-hin t-he s-ame -Puhcti-nn- as_____
described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.
Because of the diversity of sensors available to provfde initiation signals and the redundancy of the ECCS design, an allowab1e out of service time of 24 hours has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable chan~el cannot be restored to OPERABLE status wtthin the allowab1e out of service time 1 Condition H must be entered and its Required Action taken. The Requtred Actions do not allow pla,cing the channel in trip since this action woulo either cause the i~itiation or it would not necessarily result in a safe state for the channel in all events .
* PBAPS UNIT 2                    B 3.3-120                      Revision No. 145
 
ECCS Instrumentation B 3.3.5.1
* BASES ACTIONS (continued)
D,l, D,2.1, and D,2,2 Required Action D.l is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the saate. Function result in a complete loss of automatic component initiation capability for the HPCI System. AutOlllitic component initiation capability is 1ost if two function 3.d channels or two Funct.ion 3.e channel$
are inoperable and untripped. In this situation (loss of automatic suction swap), the 24 hour allowance of Required Actions D.2.1 and D.2.2 is not appropriate and the HPCI System must be declared inoperable within 1 hour after_
discovery of loss of APCI initiation capability. As noted, Required Action 0.1 is only applicable if the HPCI pump suction is not al i.gned to the suppression pool, since, if a1i gned., the Function 1s al ready perfarmed:
The Completion Ti.me is intended to allow the operator time to evaluate a.nd repair any discovered inoperabi1 ities. T~is Completfon Time also allows for an exception to the normal
                    *time zeroa for beginning the allowed outage time "clock. u
                  .For Required Action D.l, the Completion Time only begins upon discovery that the HPCI System cannot be automatically a1 i gned to the s1,1ppress ion pool due to two i nopera.b le,,
untripped channels in the same Function. The 1 hour
                ---eompletion-Timr-from-discovery-oH*oss-*of*tnitiatinn -~ - -- *------
capability is acceptable because ft minimizes risk while allowing time for restoration or tripping of channels.
Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 5) to pennit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE .status withtn the allowable out of service time, the channel must be placed tn the tripped conditi,on per Required Action 0.2 .. 1 or the suction source ltllst be aligned to the suppression pool per Required Action D.2.2. Placing the inoperable channe1 1n trip perfonus the intended function of the channel (sh.ifting the sucti.on. source to the suppression pool). Performance of either of these two Required Actions will allow operation to continue. If Required Action D.2.1 or D.2.2 is performed, measures should be taken to "ensure that the HPCI System
{continued)
* PBAPS UNIT 2                        B 3 .* 3-121                    Revisi.on No. O
 
ECCS Inst r*umenta t 1on B 3.3.5.1
* BASES ACTIONS      0.1. D.2.1. and D.2.2 (continued) piping remains filled with water. Alternately, if it is not desired to perform Required Actions 0.2.1 and D.2.2 (e.g.,
as in the case where shifting the .suction source could drain down the HPCI suction p~ping), ConditioQ H must be entered and its Required Action taken.
E.l and E.2 Required Action E.1 is intended to ensur~ that appropriate actions are taken if multiple, inoperable channels withih the Core Spray and Low Pressure Coolant Injection Pump, Discharge Flow - Low (Bypass) Functions result in redundant automatic initiation capability being lost for the feature(s). For Required Action E.1, the features would be those that are initiated by Functions l.d and 2.g (e.g., low pressure ECCS). Redundant automatic initiation capability is lost if (a) two or more Function l.d channels are inoperable affecting CS pumps in different subsystems or Cb) three or more Function 2.g channels are inoperable.
Since eaon inoperable channel would have Required Action E.1 applied separately (refer to ACTIONS Note). each inoperable channel wou]d only require the affected low-pressu~e-ECCS pump to .be declared inoperable. However1 since channels for more than one low pressure ECCS pump are inoperable, and the Completion Times started concurrently for the channels of the Tow pressure ECCS pumps, this results tn the affected low pressure ECCS pumps being concurrently declared inoperable.
I n t hi s s it ua t i on ( l os s of red un da nt a utom at i c i nit i a t i on capability). the 7 day allowance of Requir~d Action E.2 is not appropriate and the subsystem associated with each inoperable channel must be declared inoperilble within 1 hour. A Note is also provided (Note 2 to Required Action E.1) to delineate that Required Action E.I is only applicable t~ low
* PBAPS UN IT 2                          B 3.3-122                          Revision No. 145
 
ECCS lnstrumentation B 3.3.5.1 BASES
  .ACTIONS      E.l and E,2  (continued) pressure ECCS Functions. Required Action E.l is not applicable to HPCI Function 3.f since the loss of one channel results in a loss of.function (one-out-of-one logic). This loss was considered during the development of Reference 5 and considered acceptable for the 1 days allowed by Required Action E.2.
The Completion Time 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 zeron for beginning the allowed outage time "clock..
* For Required Action E.1, the Completion Time only begins upon discovery that a redundant feature in the same system (e.g~, both CS subsyste11S) cannot be automatically initiated due to inoperable channels within the same Function as described in the paragraph above. The l hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.
If the instrumentation that contro1s the pump minimum flow valve is inoperable, such that the valve will not automatica-lly- open, extended pump operation.with no.. _
injection path available could lead to pump overheating and failure. If there were a failure of the instrumentation, such that the valve. would not automatically close, a portion of the pump flow could be diverted from the reactor vessel inj.ection path, causing insufficient core cooling. These consequences can be averted by the operator's manual control of the valve, whtch would be adequate to maintain ECCS pump protection and required flow. Furthen110re, other ECCS pumps would be sufficient to c011plete the assumed safety function if no addititmal single failure were to occur. The 7 day Completion Time of Requtred Action L2 to restore the inoperable channel to OPERABLE status is reasonable based on the remaining capability of the associated ECCS subsystemst the redundancy available in the ECCS design, and the low probabil tty of a OBA occurring during the a11 owed out of service time. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, C-0ndition H must be entered and its Required Action taken.
The Required Actions do not allow placing the channel in trip since this action would not necessarily result in a safe state for the channel in all events *
* PBAPS UNIT 2                  B 3.3-123
{continued)
Revision No. 0
 
ECCS Instrumentation
                                                                            , B 3.3.5.1 BASES ACTIONS        F.1  and F.2 (continued/
Required Action F.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within similar ADS trip system A and B Functions result in redundant automatic initiation capability being lost for the ADS. For example, redundant automatic initi9tion capability is lost if either (a) one or more Function 4.a channel and one or more Function 5.a channel are inoperable and untripped, (b) one or more Function 4.b channel and one or more Function 5.b channel are inoperable and untripped,. (c) one or more Fundion 4.d channel and one or more Function 5.d channel are inoperable and untripped, or (d) one Function 4.e channel and one Function 5.e channel are inoperable and untripped.
In this situation (loss. of automatic initiation capability),
the 96 hour or 8 day allowance, as applicable, of Required Action F,2 is not appropriate and all ADS valves must be declared inope,rable within 1 hour after discovery of loss of ADS initiation capability .
* The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Co_rnple1i_Qn Time__tl~o alJow_s fQr_an ..excep:lion tQ __tb_e _nor1m1t "time ze.ro" fer beginning the allowed outage time "clock."
For Required Action F.l, the Completion Time only -begi-ns upon discovery that the ADS cannot be automatically initiated due to inoperable, untripped channels within similar ADS trip system Functions as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 8 days has been shown to be accepta.ble (Ref. 5) to permit restoration of any inoperable.
channel to OPERABLE status 1f both HPCI and RCIC are OPERABLE. If either HPCI or RCIC is inoperable, the time is shortened to 96 hours. If the status of HPCI or RCIC changes such that the Completion Time c.hange.s from 8 days to 96 hours, the 96 hours begins upon discovery of HPCI or RCIC inope.rability. However, the total time for an inoperable, unt~ipped channel cannot exceed 8 days. If the status of d
PBAPS UN IT 2                      B 3.3-124                        Revision No. 58
 
ECCS InstrLimentation B 3.3.5.1
* BASES ACTIONS      F.1 and E,2              (continued)
HPCI or RCIC changes such that the Completion Time changes from 96 hours to 8 days, the "time zero'' for beginning the 8 day "clock'' begtns upon discovery of the inop~rable, untri pped channel . If the i nope rab l  channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action F.2. Placing the inoperable channel in trip would conservatively compensate for the i no,per,abil Hy, restore capability to a.ccommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing th inoperable channel in trip would result in an initiation), Condition H must be entered and its Required Action taken.
G.1 and G,2 Required Action G.1 is intended to ensure that apprapriate actions are taken if multiple, inoperable channels withi11
* similar ADS trip system Functions result in automatic initiation capability being lost for the ADS. For example, automatic initiation ea.pability is lost if either (a) one Fffrfcl:.fi'.l'fr 4 .-c -chann-el an*a one Fun ct ion 5. c --dianneT-fre -
inoperable, (b) a combination of Function 4.f, 4.g, 5.f, and 5.g channels are inoperable such that channels asso'Ciated with five or more low pressure ECCS pumps are inoperable, or (c) one or more Function 4.h channels and one or more Function 5.h channels are inoperable.
In this situation (loss of automatic initiation capability),
the 96 hour or 8 day allowance, as applicable, of Required Action G.2 ts not appropriate, and all ADS valves must be declared inoperable within 1 hour after discovery of loss of ADS initiation capability.
The Completion Time is i ntende*d to all ow the operator- time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for be.ginning the aTlowed outage time "clock."
For Required Action G.1. th.e Completion Time only begins PBAPS U:NIT 2                              B 3.3-125                          Revision No. 83
 
ECCS Instrumentation B 3.3.5.1
* BASES ACTIONS      6.1 and 6,2 (continued) upon discovery that the ADS cannot be automatically initiated due to inoperable channels within similar ADS trip system Functions as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capabil'ity is acceptable because it minimizes risk while allowing time for t"estoration or tripping of channels.
Because of the diversity of sensors avtilable to provide initiation signals and the redundancy of the ECCS design, ah allowable out of service time of 8 days. has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE .status if both HPCI and RCIC are OPERABLE (Required Action G.2). If either HPCI or RCIC i*s inoperable, the time shortens to 96 hours*. If the status of HPCI or RCIC changes such that the Completion Time changes from 8 days to 96 hours, the 96 hours begins upon discovery of HPCI or RCIC inoperabi.lity. However, the total time for an inoperable channel cannot exceed 8 days. If the status of HPCI or llCIC changes such that the Completion Time changes from 96 hours to 8 days, the *time zero* for beginning the 8 day *clock"' begins upon discovery of the inoperable channel. If the inoperable channel cannot be res to.red to OPERABLE status within the a11 owab1 e out of
              ~service -t-ime, Condition -H *must-be-enter-ed--'itid~its -Required--
Action taken. The Required Actions do not allow placing the.
channel in trip since this action would not necessarily result in a. safe state for the channe1 in a11 events.
H.J.
With any Required Action and associated Completion Time not met, the associated feature(s) 1nay be incapable of perform,i ng the intended function,. and the supported feature(s) associated with inoperable untripped channels must be declared inoperable imediately.
(continued).
* PBAPS UNii 2                    B 3.3-126                        Revision No. O
 
ECCS Instrumentation B 3.3.5.1
* BASES  (continued)
  'SURVEILLANCE REQUIREMENTS As noted in the beginning of the SRs, the SRs for each ECCS instrumentation 'Function are found in the SRs column of Table 3.3.5.1-1.
The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours as follows: (a) far Functions 3.c and 3.f; and Cb) for Functions other than 3.c and 3.f provided the associated Function or the redundant Function maintains ECCS in1tiation capability. Upon completion of the Surveillance, or expiration of th.e 6 hour allowance, the channel must be.
returned to OPERABLE status or the applicable Cond1tion entered and Required Actions taken. This Note is based on t h*e rel i ab11 it y an a l y s. i s (Re f. 5 ) a s s ump t i on of t he a ve r a ge time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not sig_nificantly reduce the probability that the ECCS will initiate when riecessary .
* SR    3,3,5.1.1 Performa)lce of the CHANNEL CHECK ensures that a gross fail ureJ of -, nitr_u.mentatTon    has not -occur-red*. - -A CHANN(L c*HETK-fs - ~
normally a comparison of the parameter indicated on one channel to a s1milar parameter on other channels. It is based on the assumption that instrument channels monitoring the sa.me par,ameter should read approximately the same value.
Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK guarantees that undetected outright channel fail ure is limited; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION ..
Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, inc1uding indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit,
* PBAPS UN IT 2                              B 3.3-127                                  Revision No. 86
 
ECCS Instrumentation B 3.3.5.1 BASES SURVEJLLANCE    SR 3.3.5,1.1      (continued}
REQU I REMEN1S 1he Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel.s during normal operational use of the displays associated with the channels required by the LCO.
SR 3,3.5,1.2 A CHANNEL FUNCTIONAL TEST is performed oO each required channel to ensu,re that the entire channel will perform the intended function. Any set point- adjustment shal T be consistent wi.th the assumptions of the curre,nt plant specific setpoint methodology.
The ~urvei l] ance Fr*equency is controlled under the Surve1llqnce Frequency Control Program.
SR 3,3,5,1.3 and SR 3.3.5,1,4
* A CHANNEL CALIBRATION is a complete check of the i.nstrument loop and the sensor. Tbis test verifies the channel
                -responas--to- ttie-measured- pa rame-Eer- -wilhTr'lfhe -necess:a-ry-- ----- -- -
range and accuracy. GHANN-EL CALIBRATION leaves the channel adjusted to account tor i r.istrument drifts between successive calibrations, tonsistent with the assumptions of the current plant specific setpoint methodology.
The Surveillance Frequency is controlled under the Survei 11 ance Frequency Control Progrgm .
* PBAPS :UN IT 2                      B 3.3-128                        Revision No. 86
 
tees  Instrumentation B 3.3.5.1 BASES SIJRVEI LLANCE            SR      3,3:,5,1.5 REQUIREMENTS (continued)            The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPtRABILITY of the required initiation ~ogic for a specific channel. The system functional testing performed in LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to complete testing of the assumed safety fURction.
The Survei 71 ance Frequency is contr'Ol led under the Surveillance Frequency Control Program.                                            I.
REFERENCES                1.        UFSAR, Section 6.5.
: 2.        UFSAR, Section 7.A.
: 3.        UFSAR, Cnapter 14.
: 4.        NEDC-32163-P, "Peach Bottom Atomic Power Station Units 2 a.nd 3, SAFER/GESTR-LOCA, Loss-of-Coolant Aceident Arial ys is," Janua rY 1993.                              *
: 5.        NEDC-30936~P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation
            -- --- -- --- - - -- --- Inst rurnenta t 1-011 ;-Part *""2-;" -oecemb*e r -Ht88; * -~~ ~~ -- -- - ~ -
i PBAPS UN IT 2                                      B 3.3-129                                Revision No. 86
 
RClC System Instrumentation B 3.3.5.2
* B 3 *3 INSTRUMENTATION B 3.3.5.2 Reactor Core Iso,lation Cooling (RC.IC) System Instrumentation BASES BACKGROUND        The purpose of the RCIC System instrumentation is to initiate actions to ensure adequate core cooling when the reactor vessel 1s isolated from, its primary heat sink (the main condenser) and honnal coolant makeup flow from the Reactor Feedwater System is insufficient or unavailable, such that RCIC System initiation occurs and maintains sufficient reactor water*level such that an initiation of the low pressure Emergency Core Cooling Systems (ECCS) pumps does not occur. A more compl;ete discussion of RCIC System operation is provided in the Bases of LCO 3.5.3, *RCIC ,
System."
The RCIC System may be, initiated by automatic means~
Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low (Level 2). The variable is monitored by four transmitters that are connected to four pressure compensation instruments. The outputs of the pressure compensation instruments are connected to relays whose contacts are arranged 1n a one-out-of~two taken twice logic
                    ,ar,rangement. --Once -in i ti-ated-, the -RC I-C- -1 og-i-c---sea ls in- an~
can be reset by the operator only when the reactor vessel water level signals have cleared.
The RCIC test line isolation valve is closed on a RCIC initiation signal to allow full system flow and maintain prima,ry conta,inment isolated in the event RCIC is not
                    <>>perating.
The RCIC System also monitors the water level in the condensate storage tank (CST) since this is the initial source of water for RCIC operation. Reactor grade water in the CST is the normal source. Upon receipt of a RCIC initiation signal, the CST suction valve is automatically signaled to open (it i,s normally in the open position) unless the pU11J> suction from the suppression pool valves is open. If the, water _level in the CST falls below a preselected leve,l, first the suppression pool suction valves autoraatically open, and then the CST suction valve automatically closes. TWQ level switches are used to detect low water level in the CST. Either switch can cause the suppressi'on pool suction valves to open. The opening of the
{continued}
PBAPS UNIT 2                          B 3.3-130                                  Revision No. 0
 
RCIC System Instrumentation B 3.3.5.2
* BASES BACKGROUND (continued) suppression pool suction valves causes th-e CST suction valve to close. This prevents losing suction, to the pump when automatically transferring suction from the CST to the suppression pool on low CST level.
the RCIC System provides makeup water to the reactor until the reactor vessel water level reaches the 'high water level (Le.vel 8) setting (two-out-of-two logi,c), at wtiich time the RCIC steam supply valve closes. The RCIC System restarts if vessel level again drops to the low level initiation point (Level 2).
APPLICABLE        llle function of the RCIC-System is to respond to transient SAFETY ANALYSES,  events by producing makeup coolant to the reactor. The RCIC LCO, and        -  System is not an Engineered Safeguard System and no credit APPLICABILITY      is taken in the safety analyses for RCIC System operation.
Based on its contri buti'on to the reduction of overa11 plant risk, however, the system,, and therefor-e its instrumentation meets Criterion 4 of NRC Policy Statement.
The OPERABILITY of the RCIC System instrumentation is dependent upon the OPERABILITY of the individual tnstrumentation channel Functions specified in
                        -Table-----3 .3-. 5.-2-1.----~Each- Funct-i on--must-have--a* required- number~- -
of OPERABLE channels with their .setpoints withfo the specified Allowable Values, where appl"opriate. A channel is inoperable if its actual trip setting is not within its required A11owable Value. The actual setpoint ts calibrated consistent with applicable setpo;nt methodology assumptions.
Allowable Values are specified for each RCIC System instrumentation Function specified in the Table. Trip setpoints are specified i.n the setpoint calculations. The setpoints are selected to ensure that the settings do not exceed the Allowable Value between CHANNEL CALIBRATIONS.
Operation with a trip setting less conservative than the trip setpoint, but within its Allowable Value, is acceptable. Each Allowable Value specified accounts for instrument uncertainties appropriate to the Function. These uncertainties are descrtbed in the setpoint methodology.
                                                                                            <continued}
PBAPS UNIT 2                                  8 3.3-131                          Revision No. 0
 
RCIC System Instrumentatioh B 3.3 .. 5.2 BASES APPLICABLE      lhe individual Functions are required to be OPERABLE 1n SAFffi ANALYSES, MOOE 1, and 1n MOOES 2 and 3 with reactor steam dome LCO, and        pressure> 150 psig since this is when RCIC is required to APPLICABILITY    be OPERABLE. (Refer to LCO 3. 5. 3 for App 11 cab1 li ty Bases (continued)  for the RCIC System.)
The specific Applicable Safety Analyses, LCO, and App-licab1lity discussions are- listed below on a Function by Function basts.
I. Rea<;tor Vessel Water Level-Low Low <Level 2)
Low reactor pressure vessel (RPV) water level indicates that normal feedwater flow is insufficient to maintain reactor vesse1 water level -and that the capabil i ty to coo1 the fue 1 may be threatened. Should RPV water level, decrease too far, fuel damage could result. Therefore, the RCIC System is initiated at Level 2 to assist in maintaining water level above the top of the active fuel.
Reacto,r Vessel Water Level-Low Low (Level 2) signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water--(reference leg)- and the pr.essure due -to- the -actual- --
water level (variable leg) in the vessel.
The Reactor Vessel Water Level-low Low (Level 2) Allowable Value is set high enough such that for complete loss of feedwater flow, the RCIC System flow with high pressure coolant inject.ion assumed to fail will be sufficient to avoid tnitiation of low pressure ECCS at Level 1.
Four channels of Reactor Vessel Water Level-Low Low (Level 2) Function a~ available and are required to be OPERABLE when RCIC 1s required to be OPERABLE to ensure that no single instrUJQent failure can preclude RCIC initiation.
Refer to LCO 3.5~3 for RCIC Applicability Bases.
(continued)
PBAPS UNIT 2                      B 3.3-132                        Revision No. o
 
RCIC System Instrumentation B 3.3.5.2
* BASES APPLICABLE SAFITY ANALYSES,
: 2. Reactor Vessel Water Level-High {Level Bl LCO, and          High RPV water level indicates that sufficient cooling water APPLICABILITY      inventory exists in the reactor vessel such that there is no (continued}    danger to the. fuel. Therefore, the Level 8 signal 1s used to close the RCIC steam supply valve to prevent overflow into the main stea111 lines (MSLs).
Reactor Vessel Water Level-High (Level 8) signals for RCIC are initiated from four level transmitters, which sense, the difference between the pressure due to a constant column of water (reference leg) and the pressu,re due to the actual water level (variable leg) in the vessel. These four level transmitters are connected to t~o pressure compensation instruments (channels).
The Reactor Vessel Water Level-High (Level 8), Allowable Value is high enough to preclude iSolating the injection valve of the RCIC during normal operation, yet low enough to trip the RCIC System prior to water overflowing into the MSLs
* Two channels of Reactor.Vessel Water Level-High (Level 8)
Function are available and are required to be OPERABLE when
                            -RG-IC~ is required--t-o -be OPERABLE to* ensure--that-no-single--
instrllll1E!nt failure can preclude RCIC 1.nitiation. Refer to LCO 3 *. 5.3 for RCIC Applic~bility Bases.-
3, Condensate Storage Tank Leve1-Low Low level in the CST indicates the unavailability of an adequate supply of makeup water from this nol"1Jlal source.
Normally, the suction valve between the RCIC pump and the CST 1S open and, upon receiving a RCIC initiation signal, water for RCIC injection would be taken from the CST.
However, if the water level in the CST falls below a preselected level, first the suppression pool suction valves automaUcally open, and then the CST suction valve automatically closes. This ensures that an. adequate supply of makeup water is available to the RCIC pump. To prevent losing suction to the PllDP, the suction valves are interlocked so that the, suppression pool suction valves must be open before the CST suction valve automatically closes.
(continued}
* PBAPS UNIT 2                          B 3.3,-133                      Re.vision No. 0
 
RCIC System Instrumentation B 3.3.5.2
* BASES APPLICABLE SAFETY ANALYSES, 3, Condensate Storage Tank Level-LQw (continued)
LCO, and          Two level swi.tches are used to detect low water level in the APPLICABlt.ITY    CST~ The Condensate Storage Tank Leve1--low Function Allowable Value is set high enough to, ensure adequate pump suction head wh1l_e water is being taken from the CST.
Two  channels of the CST Level-Low Function are available and are required to be OPERABLE when RCIC iS required to be OPERABLE to ensure that no single instrument failure can preclude RCIC swap to suppression pool source.        Refer to LCO 3.5.3 for RCIC Applicability Bases.
ACTIONS            A Note has been, provided to IIOdify the ACTIONS related to RCIC System, inst&#xa5;"umenta.tion channel's. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits wi11 not result in separate entry into the Condition. Section 1.3 also specifies that
* Required Actions of the Condition continue to ap~ly for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for
                  --inoperable-- RCIG- System-  ns-trumentati on channe1-s-provi de appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable RCIC System instrumentation channel.
                    &l Required Action A.I dtrects entry into the appropriate Cond1Uon referenced in Table 3.3.5.2-1. The applicable Condition referenced tn the Table is Function dependent.
Each time a channel is discovered to b~ inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.
(continued}
* PBAPS UNIT .2                        B 3.3-134                        Revision No. 0
 
RCIC System Instrumentation B 3.3.5.2
* BASES ACTIONS (continued)
B,1 and B.2 Required Action B.l is intended to ensure that appropriate actions are taken if aultiple, inoperable, untripped channels w:lthin the saae Function result in a complete loss of automatic initiation capab11 ity for the RCIC System. In this case, automatic initiation capability is lost if two Function 1 channels in. the same trip system are inoperable and untripped. In this situation (loss of automatic initiation capability), the 24, hour allowance of Required Action B.2 is not appropriate, and the RCIC System must be declared in<>perable within 1 hour after discovery of 1oss of RCIC initiation capability.
* The Completion Time iS intended to allow the *operator time to ,evaluate and repair any discovered inoperabil ities. This Completion Time also allows for an exception to the nonnal
                  *time zero~ for beginning the allowed outage time *clock.a For Required Action 8.1, the Completion Time only begins upon discovery that the RCIC System cannot be automatically initiated due to two or 1ROre inoperable, untripped Reactor
* Vessel Water Level-Low Low (Level 2) channels such that the trip system loses initiation capability. The 1 hour Completion Time frorq discovery of loss of initiation capabtl1ty-is**acceptable *because it minimizes risk whHe- *~* -
allowing time for restoration or tripping *of channels.
Because of the redundancy of sensors ava.11 able to provide inUi.ation signals and the fact that the RCIC Sy.stem is not assumed in any accident or transient analysh, an allowable out*of service time of 24 hours has been shown to be acceptable(Ref. 1) to perait restoration of any inoperable channel to OPERABLE stJtus. if the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per 'Required Action 8.2. Placing the inoperable channel 1n trip W'ould. conservatively compensate for the inoperabiHty, restore capability to accommodate a single faJlure, and allow operation to conttnue.
Alternately, if it is not desired to place the channel 1n trip {e.g., as in the case where placing the inoperable channel in trip would result in an initiatfon), Condition E IDUSt be entered and its Required Action taken.
(continued}
* PBAPS UNIT 2                      B 3.3-135                    Revision No. O
 
RCIC System Instrumentation B 3 .3. 5. 2.
* BASES ACTIONS (continued)
Ll A risk based analysis was performed and detenni.ned that an allowable out of service t1111e of 24 hours (Ref. 1) is acceptable to penni.t restoration ,of any inoperable channel to OPERABLE status (Required Action C.l). A Required Action (similar to Required Action B.l) limiting the allowable out of service time, if a loss of automatic RCIC initiation capability exists, is not required. This Condition applies to the Reactor Vessel Water Level---H1gh (Level 8) Function whose l,ogic is arranged such that any- inoperable channel will result in a loss of aut0111atic RCIC initiation
* capability (closure of the RCIC steam supp*ly valve}. As stated above, this loss of automatic RCIC initiation capability was analyzed and determined to be acceptable.
The Required Action does not allow placing a channel tn trip since this acti.on would not necessarily result in a safe state for the channel in all events.
P, 1. D. 2. I, and D. 2, 2
* Required Action 0-.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped
                - channels-within the-same-F:unct-'ion -result-in- automatic -
component initiation capability being lost for the feature(s). For Required Action 0.1, the RCIC System is the only associated feature.. In this case, automatic initiation capability is lost if two Function 3 channels are inoperable and untripped. -In this situation {loss of automatic suction swap), the 24 hour allowance of Required Actions D.2.1 and D.2.2 is only appropriate after Action 0.1 has been perfo.rmed. Action 0.1 requires that the RCIC System. be declared inoperable within l hou.r from discovery of loss of RCIC initiation capability. As noted, Required Action D.J is only applicable if the RCIC pump suction is not al i.gned to the suppression pool since., if aligned, the Function is already perfonned.
{continued)
* PBAPS UNIT 2                        B 3.3-136                      Revision No,. 0
 
RCIC System Instrumentation B" 3.3.5.2
* BASES ACTIONS        P,l, D,2.1, and D,2.2 (continued)
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time als*o allows for an exception to the normal ntime zero" for beginnfng the allowed outage time *c1ock *.            11 For Required Action 0.1, the Completion Time only begtns upon discovery that the RGIC System cannot be automatically aligned to the suppressic;m pool due to two inoperable, untripped channels in the same Function. The 1 hour
                .,C9:1DPletion Time from discovery of loss of initiati,on
              , capability is acceptable because it minimizes risk.while allowing time for restoration or tripping of channels.
Because the RCIC System is not assUtRed in any accident or transient analysis, an allowable out of service time of 24 hours, has been shown to be acceptable (Ref. l) to permit res tor at ion of any inoperable channe1 to OP.ERABLE status.
If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition *per Required Action 0.2.1, which performs the intended function of the channel. Alternatively, Required Action 0.2.2 allows the manual alignment of the RCIC suction to the suppression poo-1,wh i ch *also -perfonns-the* -intended -fl.mc-t-i on-.---l-f--- ~~ --~
Required Action D.2.1 or 0.2~2 is performed, measures should be taken to ensure that the RCIC Systm piping remains filled with water. If it is not desired to perform Required Actions 0.2.1 and 0.2.2 (e.g., as in the case whe.re shifting the suction source could drain down the RCIC suction piping), Condition E must be entered and its Required Action taken.
Ll With any Required Action and associated Completion Time not met., the RCJC System -1ay be incapable of perfonuing the intended function, and the RCIC System must be declared inoperable iamediately.
                                                                            * (continued}
* PBAPS UNIT 2                        B 3.3-137                            Revision No. o
 
RCIC System Instrumentation B 3.3.5.2 BASES  (continued)
SURVEILLANCE        As noted in the beginning of the SRs, the SRs for each RCIC REQUIREMENTS        System instrumentation Function are found in the SRs column of Table 3.3.5.2-1.
The Surveillances are modified by a Note to indicate that when a c ha nnel 1s pl a oe d i n a n i nope r a bl. e s ta t us s ol e l y f o r performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows:
(a) for up to 6 hours for Function 2 and Cb} for up to 6 hours for Functions 1 and 3, provided the associated Function maintains trip capability. l:Jpon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the appl4cable Condition entered and Required Actions taken.
This Note is based on the reliability analysis (Ref. 1) assumption of the .average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RCIC will initiate when necessary .
* SR    3
* 3
* 5,. 2
* 1 Performance of the CHANNEL CHECK ensures that a gross fa;-]  re- or-instramentati on -has not-occurred. --A CHANNEi.:--- -" - -- -
CHECK is normally a. comparison of the parameter indicated o,n one channel to a parameter on other similar channels. Lt is I
based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.
Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit .
* PBAPS UNIT 2                                B 3.3-138                          Revision No. 86
 
RCIC System Instrumentation B 3.3.5.2
* BASES SURVEI U.ANCE REQU I REMf:NTS SR  3.3.5.2.1  (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays assnc1ated with the channels required by the LCO.
SR  3 . 3.5.2.2 A CHANNEL FUNCTIONAL TEST 1s performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .
* SR  3.3.5,2,3 A CHANNEL CALIBRATION is a complete check of the instrument foop and *u1e sens*o-r. - rhl s "'tes*t v-efifi e*s the thann:el -
responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION le~ves the channel adjusted to account f Dr 1nst rument drifts between successive calibrations, consistent with the plant spectfic setpoint methodology.
The Surve1llance Frequency is controlled under the Surveillance Frequency Control Program.
SR  3.3,5.2.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system f~nctional testing performed in LCO 3.6.3 overlaps th1s Surveillance to provide complete testing of the safety function .
* PBAPS UN IT 2                      B 3.3-139                            Revision No, 86
 
RCIC System Instrumentation B 3.3.5.2
* BASES SURVEILLANCE REQUIREMENTS SR  3,3,5,2,4      (continued)
The Surveillance Frequency is controlled under the Surveiliance Frequency Control Program.
REFERENCES    1. GENE-770-06-2, ~Addendum to Bases for Changes to Surveillance Te5,t Inter'tals and Allowed Out-Of"Servic1; Times for Selected Instrumentation Technical Spec i fi cat i on s , '' February 19 91 .
* PBAF>S UNIT 2                      B 3.3-140                        Revision No. 86
 
Not Used B 3.3.5.3 B  3.3 INSTRUMENTATION
* B 3.3.5.3  Not Used
* PBAPS UNIT 2          8 3.3-140a Amendment No. 145
 
RPV Water I.nve:ntory Control Instrumentation B 3.3.5.4
* B 3.3  INSTRUMENTATION B 3.3.5.4 BASES Reactor Pressure Vesse1 <RPV) Water Inventory Control Instrumentation BACKGROUND        The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor c0olant inventory to bel.ow the TAF. If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.
rechnical Specifications are required by 10 CFR 50.36 to include limiting safety system settings (LSSS) for variables that have 5ignificant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has ~een placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded."
* The Analytical Limit is the limit of the process variable at which a safety action is initiated to ensure that a SL is not exceeded. Any automatic protec_ti_on_action _that o_c_curs on __ _
                    --r.eacfilng tn-e AnaTyticai Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automati.c protection channels must b.e chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur. The actual settings for the automatic isolation channels are the same as those established for the same functions in MODES 1, 2, and 3 in LCO 3.3.5.1, "Emergency Core Cooling System
([CCS) Irstrumentation," or LCO 3.3.6.1, "Primary Containment Isolation instrumentation".
With the unit in MODE 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses. RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release 0f radioactive material should a draining event octur. Under the definition of DRAIN TIME, some penetration flow paths may be excluded from the DRAIN TIME calculation if they will be isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumenta.t10n.
con inued PBAPS UN IT 2                          B 3 .. 3-140b                  Revision No. 145
 
RPV W.ater Inve.ntory Control Instrumentation B 3.3.5.4
* BASES (continued) fiACKGROUND (continued)
The purpose of the RPV Water Inventory Control Instrumentation is to s1,1pport the requirements of LCQ 3.5.4, "Reactor Pressure Vessel ( RPV) Water Inventory Control," and the definition of DRAIN TIME. There are functions that are required for manual initiation or operatfon of the ECCS injection/spray subsystem required to be OPERABLE by LCO 3.5.4 and other functions that support automatic isolation of Resid!ual Heat Removal subsystem and Reac.tor Water Cleanup system penetration flow path(s} on low RPV water level.
The RPV Water Inventory Control Instrumentation supports operation of core spray (CS) and low pressure coolant injection (LPCI). The equipment involved with each of these systems is described in the Bases for LCO J.5.4.
APPLICABLE        With the unit in MODE 4 or 5, RPV water inventory control is SAFETY ANALYSIS    not required to mitigate any events or accidents evaluated in the safety analyses. RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur .
                    .f:. _9oub1e-ended guil_lo.ti_oe bre_ak of the Reactor Coolpnt System (RCS) is not postulated in MODES 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile p1p1ng systems. Instead, an event is postulated in which a single operator error or initiating event alJows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode fa il ur e Ce . g . , s e i s mj c e ve nt ( ex ce pt whe n t..h e r i s k i s assessed and managed in accordance with TS LCD 3.0.8), loss of normal power, single human error). It is assumed, based on engineering judgment, that while in MODES 4 and 5, one low pressure ECCS injection/spray subsystem can be manually initiated to maintain adequate reactor vess~l water level.
As discussed in References l, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety. Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).
Permissive and interlock setpoints are generally considered as nominal values without regard to measurement accuracy.
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by PBAPS UN IT 2                              B 3.3-140c                              Revision No. 145
 
RPV Water Inventory Control Instrumentation B 3.3.5.4 BASES (continued)
APPLICABLE        Function basis.
SAFETY ANALYSES (continued)      Core Spray and    Low Pressure Coolant Iniection Systems l,a, 2.a, Reactor Pressure - Low (Injection Permissive)
Low reactor pressure signals a(e used as permissives for the low pressure ECCS injection/spray subsystem manual injection functions. This function ensures that, prior to opening the injection valves of the low pressure ECCS subsystems, the reactor pressure has fallen to a value below these subsystems' maximum design pressure. Whlle i't is cissure'Cl during MODES 4 aTid 5 that the reactor pressure will be below the ECCS maximum design pressure, the Reactor Pressure - Low signals are assumed to be OPERABLE and capable of permitting init1at1on of the ECCS.
The Reactor Pressure - Low signals are initiated from four pressure transmitters that sense the reactor dome pressure.
The' A1lowable Value is low errnugh to prevent overpressur1ng the equipment in the low pressure ECCS.
The four channels of Reactor Pressure - Low Function are
_r~qui r_~_ to be_ OPE_B._AB_LE j n_MODES _4 _and 5 when ECCS-----manua l initiation is required to be OPERABLE by LCD 3.5.4.
1,b. 2,b. Core Spray        and Low Pressure CooJant Injection Pump Discharge Flow - Low        (Bypass)
The minimum flow instruments are provided to protect the associated low pressu~e ECCS pump from overheating when the pump is operating and the associated irijection valve is not fully open. The minimum flow line valve is opened when low flow is sensed, and the valve is automatically closed when the f1ow rate is adequate to protect the pump.
One differential pressure switch per ECCS pump is used -to detect the associated subsystems' flow rates. The logic is arranged such that each transmitt~r causes its associated minimum flow valve to open. The logic will close the minimum flow valve once the closure setpcint is exceeded.
The LPCI minimum flow valves are time d~layed such that the valves will not open for 10 seconds after the switches detect low flow. The time delay is provided to limit reactor vessel inventory loss during the startup of the Residual Heat Removal (RHR} shutdown cooling mode .
* PBAPS UNIT 2                          B 3.3-140d continue Revision No. 145
 
RPV Water Inventory Control Instrumentation B 3.3.5.4 BASES (continuedJ APPLICABLE        The Pump Discharge Flow -  Low Allowable Values are high SAFE!Y ANALYSES  enough to ensure that the  pump flow rate is sufficient to (continued)    protect the pump, yet low  enough to ensure that the closure of the minimum flow valve  is initiated to allow full flow into the core.
One channel of the Pump Discharge Flow - Low Function is required to be OPERABLE in MODES 4 and 5 when the associated Core Spray or LPCI pump is required to be OPERABLE by LCO 3.5.4 to ensure the pumps are c~pable of injecting into the Reactor Pressure Vessel when ma~ually initiated.
A note is added to TS Tab1e 3.3.5.4-1 for Function 2.b to clarify the intent of allowing credit for an OPERABLE Low Pressure Coolant Injection subsystem when it ts aligned and operating in the decay heat removal mode of RHR. This note is appropriate since the associated RHR pump minimum flow valve (while operating in the decay heat removal mode) is closed and deactivated to prevent inadvertent vessel drain down events.
1.c, 2.c. Manual Initiation
* The Manual Initiation hand switch channels introduce signals into the appropriate ECCS logic to provide manua1 ini.tJation r:ap_abiLity. The-r.e is one hand- -switch -for --each - -
CS and LPCI pump (four for CS and four for LPCI).
RHR System Isolation 3.a Reactor Vessel Water Level - Low. Level 3 The definition of DRAIN TIME allows crediting the closing of penatrati on fl ow paths that are capabl s of being isolated b,y valves that will close automatically without offstte power prior to the RPV water level being equai to the TAF when actuated by RPV water level isolation instrumentation.
The Reactor Vessel Water Level - Low I Level 3 ,Function associated with RHR System i so1 at ion may be credited for automatic isolation of penetration flow paths associated with the RHR System,.
* PBAPS UN IT 2                      B 3.3-140e                    Revision No. 145
 
RPV Water Inventory Control Instrumentation B 3.3.5.4
* BASES (continued)
APPLICABLE SAFETY ANALYSES (continued)
Reactor Vessel Water Leve1 - Low., Level 3 signals are Reactor initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Whi1e four Channels (two channels pet trip system) of the Reactor Vessel Water Level - Low, Level 3 Function are available, only two channels (all in the same trip system) are required to be OPERABLE.
The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the Primary Containment Isolation Instrumentation Reactor Vessel Water Level - Low, Level 3 Allowable Value (lCO 3.3.6.1), since the capability to cool the fuel may be threatened.
The Reactor Vessel Water Level - Low, Level 3 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME.
Reactor Water Cleanup CRWCU) System Isolation
* 4.a Reactor Vessel Water Level - Low, Level 3 The definitton of DRAIN TIME aHows crediting the closing of penetration flow paths that are capable of being isolated by valves that will close automatically without Offsite power prior to the RPV water level being equal to the TAF when a ct ua t ed by RP V wa t e r l e vel i s o1 a t i on i ns t rumen t a ti on . The Reactor Vessel Water Level - Low, Level 3 Function associated with RWGU System isolation may be credited for automatic isolation of penetration flow paths associated with the RWCU System.
Reactor Vessel Water Level - Low, Level 3 signals are initiated from four level transmitters that ~ense the difference between the pressure due to a constant column of water ( reference 1eg) and the pressure due to the <Jctua 1 wa t e r l eve l ( va r i a bi e l e g ) i n t he ve s s e l . Whi l e fo ur channels (two channels per trip system) of the Reactor Vessel Water Level - Low, Leve1 3 Function are available, only two channels {all in the same trip system) are requir-ed to be OPERABLE.
The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the RPS Reactor Vessel W~ter Level - Low, Level 3 Allowable Value (LCD 3.3.1.U, since the capability to cool the fuel may be threatened.
PBAPS UN IT 2                            B 3.3-140f                              Revision No. 145
 
RPV Water Inventory Control Instrumentation B 3.3.5.4 BASES (continued)
APPLICABLE        This Function isGlates the inboard and outboard RWCU pump SAFETY ANALYSES  suction penetration.
(continued)
The Reactor Vessel Water Level - Low, Level 3 Function is only required to be OPERABLE when automatic is.olation of the associated penetration flow path is credited in calculating DRAIN TIME.
ACTIONS          A Note has been provided. to modify tire ACTIONS related to RPV Water Inventory Control instrumentatidA channels. Sectibn 1.3, Completion Times, spec1ffe~ that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the toAdition discovered to be inoperable or not W'ithin limits will nol result in .separate entry into the Condition. Section 1.3 a1so sp,ecifies that Required Actions continue to app1y for each aaditional failure, with Completion Times based on tnitial entry i.nto the Condition. However, the Required Actions for inoperable RPV Wc;1ter Inventory Control instrumentation channels provide
* a_ppropri ate compensatory measures for separate inoperable Condition entry for each inoperable RPV Water Inventory
                    -~9ntro_Lin'.s.trume,ota+/-1on.channeL-- --~- -- - ~ *-
Ll Required Action A.l directs entry into the appropri~te Condition referenced in Table 3.3.5.4Jl. Th~ applicable Condition referenced *1n the Table is function dependent.
Each time a channel is discovered inoperable, Con~ition A is entered for that channel and provides for tr-ansfer to the appropriate sub*s-e.quent Condi ti on.
B.l and B*. 2 RHR System Isol,ation, Reactor Vessel Water Level - Low, Level 3, and Reactor Water Cleanup System Isdlation, Reactor Vessel Watel'" Level - Low, Level 3 functions, are applicable when automatic isolation of the associated pe~etrat1on flow path is credited ill calculating DRAI~ TIME. If the instrumentation is inoperable, Required Action B.l directs an immediate declaration that the associated penetration flow path(s) are incapable of automatic isolation. Required Action B.2 directs calculation of DRAIN TIME. The calculation cannot credit automatic 1s0Jation of tbe affected penetration flow paths.
PBAPS UNIT 2                        B 3.3-1409                    Re~ision No. 145
 
RPV w~ter Inve~tory Control Instrumentation B 3.3.5.4
* BASES (continued)
ACTION.S (continued)
Ll Low rea~tor steam dome pressure signals are used as pe.rmissives for the low pres,sure e:ccs injection/s.pray subsystem manua1 injection funetio:ns. If the permis*sive is inoperable, manual initiation of ECCS is prohibfted.
Therefore, the permissive must be pl.aced in the trip condition with1n l hour. With the permissive in the tr~p condition, manual initiation may b~ performed. Prior to placing the permissive in the tripped condition, the operator can take manual control of the pump and the injection valve to inject water into the* RPV.
The Completion Time of 1 hour is intended to a11ow the operator time to evaluate any discovered inoperabili'Ues .and to pl ace the ch*annel in trip .
                    .D....l If a Core Spray or Low' Pressure Coolant Injection Pump Discharge Flow - Low bypass funttion is inoperable, there ts a risk that the associated low pressure ECCS pump could
* overheat when the pump is operating and the associated injection valve is not fully open. In this condition, the
__oper~tor c_an t.ake manual _contro1 of. the pump-and the - --
injection va 1ve to ensure the pump does not overheat. Tf a manual initiation function is inoperable, the ECCS subsystem pumps can be started manually and the valves can be_opened manually. but this is not the preferred condition, Th~ 24 hour Completion Time was ch-0sen to allow time for the operator to evaluate and 0jpair any discovered inoperabilities. The Completfon Time is appropriate given the ability to manually start the ECCS pumps and open the injection valves and to manually ensure the pump does not overheat.
Ll With the Required Action and asso.ciated Completion Time of Co~dition C or D not met, the associated low pressure ECCS injection/spray subsystem may be incapable of performing the in.tended function, and must be declared inoperable immediately.                                  -
As noted in the beginning of the SRs, the SRs for each RPV W~ter Inventory Control instrument Function are found in the SRs column of Table 3.3.5.4*1 .
PBAPS UNIT 2                          B 3.3-14Qh                    Revision No. 145
 
RPV Water Inventory Control Instrumentation B 3.3.5.4
* BASES (continued)
SURVEILLANCE REQUIREMENTS SR 3.3,5.4.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHEC~ Js r:iorrna.lly a comparison of the parameter indicated 0n one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.
Significant deviations between the instrument channels could be an indication of excessive instrument drift in one cf the channels or s*omethi ng even more serious. A EHANNEL CHECk guarantees that undetected outright channel failure is limited; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEt FUNCTIONAL TEST.
Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may oe an indication that the instrument has drifted outside its limit.
* The Surveillance Frequency is controlled under the Survefllance Frequency Control Program.
Th-e CHANN:EL -CHECK suppl emerits 1 ess forrna l, but more frequent, checks of channels during normal operational use of the displays associated with the channel~ required by the LCO.
SR 3.3.5.4.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a tha_nnel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL nsr of a ralay. This is acceptable because all of the other required contacts of the relay are v~rified by other Technical Specification~ and non-Technical Specifications tests.
Any setpoint adjustment shall be consistent with the assumptions of the curr*ent plant specifi.c setpoint methodology.
The Surveillance Frequency 1s controlled under the Surveillance ~requency Control Program .
PBAPS UN IT 2                        .B 3.3-140i                    Revision No. 145
 
RPV Water Inventory Control Instrumentation B 3. 3. 5 ..4
* BASES (continued)
SURVEILLANCE REQUIREMENTS (continued)
SR 3.3,5.4,3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILIIY of the requ.ired initiation logie for a speciftc channel. The system functional testihg performed in LCO 3.5.4 overlaps this Surveillance to complete testing of the assumed*safety function.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
REFERENCES        1. Information Notice 84-81 "Inadvertent Reduction in Primary Coolant Ihventory in Boiling Water Reactors During Shutdown and Startup," November 1984.
: 2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misal1gnment of RKR Valves,' 1 August 1986.
: 3. Generic Letter 92-04, hResolution of the Issues Related
* to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(F), "August 1992.
: 4. NRG Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.
: 5. Information Notice 94-52, ''Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone l," July 1994 .
* PBAPS UN IT 2                      B 3.3-140j                  Revision No. 145
 
Primary Contaihmeht Isolation Instrumerttation B 3.3.6 .. I B 3.3  INSTRU~ENTATION 8 3.3.6.1    Pr1mary Containment -Isoljtion Instrumentation BAStS BACKGROUND          The primary containment isolation instrumentation automatically initiates closure of appropriate primar.y containment isolation valves (PCIVs}. The function of the PGIVs, in combination w1th other accident mitigation systems, ts to limit fission product release during and following postulate.ct Design Basis Accidents (DBAs). Primary containment isolation within the time limits specified for those isolation valves deslgned to close autornattcal]y ensures that the release of radioactive material to the environment wtll be consistent wtth the assumptions used in the analyses for a OBA.
* The. isolation instrumentation includes the sensors, relays, and switches that are necessary to ca~se in1tiatfon of pr1mary containment and reactor cool a.nt pressure boundary (RCPB) isolation. Most channels include electronic equipment (e.g., trip units) that compares measured input
* signals with pre-established setpoint~. When the setpoint is exceeded, the channel output relay actuates,, which then outputs a primary containment isolation signal to the fsola:tion logic; "FUnctjonal diversity is-provided by -
mon1tor1ng a wide range of independent parameters. The input parameters to the isolation logics are (a) reactor vesse:l water level, (b) reactor pre&sure, (c) main steam line (MSU flow measurement, (d) (deleted), Ce) main steam line pressure, (f) arywell pressure*, Cg) high pressure coolant injection (HPCI) and reactor core 1solat1ofl cooling (RCIC) steam 11ne flow, (h.) HPCI and RCIC steam 1ine 1fre,ssure,. (11 reactor water cleanup CRWCU) flow, (j) Standby Liquid' Control (SLC) System 1nitiat1an, (k) area ambient temperatures, (1) reactor building ventilation and refueling floor ventilation exhaust radiation, and tm) main stack radiation. Redundant sensor input signals from each parameter are provided for initiation of isolation.
Primary contai*nment iso1at1on instrumentation has in.puts to the trip logic of the isolation functtons listed below.
Ccontinuectl
* PBAPS UN.IT 2                          B 3.3-141                  Revision Mo. 134
 
Primary Containment Isolation Instrumentation B 3.3.6.1
* BASES BACKGROUND
{continued)
: 1. Main Steam Line Isolation Most MSL Isolation Functions receive inputs from ~our channels. Tne outputs f~om these channels are combined in a one-out-of-two taken twice logic to initiate f.solation of the Group I isolation valves (MSIVs and MSL drains, MSL sample lines, and recirculation loop sample line valves).
To initiate a Group I isolation, both trip systems must be tripped.
The exceptions to this arrangement are the Main Steam Line Flow-High Function and Turbine Building Main Steam Tunnel Temperature-High Flihctions.      The Main Steam Line Flow-High Function uses 16 flow channels, four for each steam line.
One chanrrel from each steam line inputs to one o:r the four trip strings. Two trip strings make up each trip system and both trip systems must trip to cause an,MSL isol~tion.          Each trip string has four inputs {one pe:r: MSL) , any one of which will trip the trip string. The trip systems are arranged in a one-out-of-two taken twice logic.        This is effectively a one-out-of-eight taken twice logic arrangement to initiat~ a Group I isolation.      The Turbine Building Main Stearn Tunnel Temperature-High Function receives inputs from twelve channels, four ch1;nnels at each of the three different
                -1occiti-ons albng -the-s*team line. Hi*gh* temperature-*brr any channel is not related to a specific MSL.        The channeJ.s are arranged in a one-out-of-two taken twice logic fo~ each location.
: 2. Primary Containment Isolation Most Primary Containment Isolation Functions receive inputs from four channels.      The outputs from these channeJ,s are arranged in a one-out-of-two taken twice logic.        Isolation of inboard and outboard primary containment isolation valves occurs when both trip systems are in trip.
The exception to this arrangement is the Main Stack Monitor Radiation-High Function. This Function has two channels, whose outputs are, arranged in two trip systems which llse a one-out-or-one logic.      Each tr,ip system isolates one valve per associated penetration. The Main Stack Monitor Radiation-High Function will isolate vent and purge valves greater than two inches in diaroeter during containment purgihg (Ref. 2) .
* PBAPS UNI'l' 2 The valves isolated by each of the Primary Containment Isolation Functions are listed in Reference 1.
B 3.3-142 (continued)
Revision No. 48
 
Primary Containment Isolation Instrumentation B 3.3,6.1
* BASES BACKGROUND (continued) 3., 4: High Pressure Coolant Injection System Isolation and Reactor Core Isolation Cooling System I,solation The Steam Line Flow-High. Functions that: isolate HPCI and RCIC receive input from two channels, with each channel comprising one trip system using a one-out-of-one logic.
Each of the two trip systems in each isolation group (HPCI and RCIC) is connected to the two valves on each associated penetration.      Each HPCI and RC::IC Steam Line Flow-High channel has a time delay relay to prevent isolation due to flow transients during startup.
The HPCI qnd RCIC Isolation Functions for Drywell Pressure-High and Steam Supply Line Pressure-Low receive inputs from fou.r channels.      The outputs from these channels are combined in a one-out-of-two taken twice logic to initiate isolation of the associated valves.
The HPCI and RCIC.Compartment and Steam Line Area Temperature-High Functions receive input from 16 channels, four channels a:t each of four different locations.        The channels are arranged in a one-out-of-two taken twice logic for each location.
                -<rlfe-HPCl *and* RCIC Steam* Lihe-Flow=--High *Functions, *-steam Supply Line Pressure-Low Functions, and Compartment and Steam Lihe Area Temperature-High Functions isolate the associated steam s~pply and turbine exhaust valves and pump suction valves. The HPCI and RGIC Drywell Pressure-High Functions isolate the BPCI and RCIC test retu,rn line valves.
The HPCI and RCIC Drywe11 Pressure-High Functions, in conjunction with the Steam Supply Line Pressure-Low Functions, is,olate the HPCI and RCIC turbine exhaust vacuum relief valves.
: 5. Reactor Water Cleanup System Isolation The Reactor Vessel Water Level_-Low (Level 3) Isola;tion Functton receives input from four Leactor vessel water level channels. The outpu~s from the reactor vessel water level channels are connected into a one-out-of-two taken twice logic which isolates both the inboard and outboard isolation valves. The RWCU Flow-!Ugh Function receives input from two channels, with each channel in one trip system u~ing a one-out-of-one logic, with one channel tripping the inboard valve and one channel tripping the outboard valves.          The SLC (continued)
EBAPS UNIT 2                        B 3.3-143                      Revision No. 48
 
Primary Containment Isolation Instrumentation B 3.3.6.1
*  ~ASES BACKGROUND    5,    Reactor Water Cleanup System Isolation    (continued)
System Isolation Function receives input from two channels with each channel in one trip system using a one-out-of-one logic. When either SLC pump is started remotely, one channel trips the inboard isolation valve and one channel isolates the outboard isolation valves.
The RWCU Isolation Function iso1ates the inboard and outboard RWCLI pump suction penetration and the outboard valve at the RWCU connection to reactor feedwater.
6,    Shutdown Cooling System Isolation The Reactor Vessel Water Level-Low (Level 3) Function receives input from four reactor vessel water level channels. The outputs from the channels are connected to a one-out-of-two taken twice logic, which isolates both valves on the RHR shutdown cooling pump suction penetratio.n, 1he Reactor Pressure-High Function receives input from two channels, with each channel in one trip system using a one-out-of-one logic. Ea.c::h trip system is connected to both Vcellves o,n the RHR shutdown cooling pump suctio n pe,netration .
1
: 7. Feedwater Recirculation Isolation The Reactor Pressure-High Function receives inputs from four channels. The outputs from the four channels are connected into a one-out~of-two taken twice logic which isolates the feedwater recirculation valves.
: 8. Traversing Incore Probe System Isolation The Reactor Vessel Water Level-Low, level. 3 Isolation Function receives input from two reactor vessel water leNel channe1s. The outputs from the reactor vessel water level channels are connected into one two-out-of-two logic trip system. The Dryw.el l Pressure-High Isolation fuh*cti on receives input from two drywell pressure channels. The outputs from the drywell pressure channels are connected into one two~out-of-two logic trip system.
When either Isolation Function actuates, the TIP drive mechanisms will withdraw the TIPs, if inserted, and close the TIP system isolation ball valves when the TIPs are fully with drawn. The redundant TIP system i sol ati on valves a*re manual shear valves.
TIP System Isolati.on Functions isolate the Group II(D) TIP
* PB,A PS UNIT 2 valves (isolation ball valves) .
B 3.3-144 (continued)
Revision No. 57
 
Primary Containment Isolation Instrumentation B 3.3.6.1
* BASES APPLICABLE SAPETY ANALYSES, LCO, and The isolation signals generated by the primary containment isolation instrumentation are implicitly assumed in the safety analyses (}f References 1 and 3 to initiate closure APPLICABILITY      of valves to limit offsite doses. Refer to LCD 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)," Applicable Safety Analyses Bases for more detail of the safety analyses.
Primary containment isolation instrumentation satisfies Criterion 3 of the NRC Policy Statement. Certain instrumentation Functions are retained for other reasons and are described below in the individual Fu~ctions discussion.
The OPERABILITY of the primary containment instrumentation i s dependent on the OPERA BI LI TY of the i ndi vi dua1 instrumentation channel Functions specified in Table 3.3.6.1-1. Each Function must have a required number of OPERABLE channels, with their setpoints within the specified Allowable Values, whe,re appropriate. A channel is inoperable if its actual trip setting is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Allowable Values, where applicable, are specified for each Primary Containment Isolation Function specified in the .
Ta b1e . - Tr i p s et poi nts a re s pe c if i e.d i n the s et po i nt calculations. The trip setpoints a.reselected to el'!sure that the setpoints do not exceed the Allowable Value between
__Cl:JANNEL .CALIBR~JIONS. Ope,ratj on_ with c1,,tri p setting Jess conservative than the trip setpoint, but within its Allowable Valu,e, is acceptable. Tr'ip setpoints are those predetermined values of butput at which an action should take place. The setpoints are compared to the actual process pc1rameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated-device (e.g., trip unit) changes state. The analytic or design limits are derived from the limiting values of the process parameters obtained from the iafety analysis or other appropriate documents. The Allowable Values are derived from the analytic or design limits, corrected for calibration, process, and instrument errors. The trip setpoints_are determined from analytical or design limits, corrected for calibrati0n, process, and instrument errors, as well as, instrument drift. In selected cases, the Allowable Values and ~rip ~etpoints are determi~ed by en~ineering j~dgement or historically accepted practice relative to the intended function of the channel. The trip setpoints determined in this manner provide adequate protection by assuring instrument and process uncertainties expected for the environments during the operating time of the associated channels are accounted for.
Certain Emergency Core Cooling Systems (ECCS) and RCIC
* PBAPS UN IT 2 valves ~e.g. minimum flow) also serve the dual function of automatic PCfVs. The signals that isolate these valves are also associated with the automatic initiation of the ECCS B 3.3-145 (continued)
Revision No. 57
 
Primary Containment !sol at ion Instrumentation B 3.3.6.1
* BASES APPLICABLE        and RCIC. The instrumentation requirements and ACTIONS SAFETY ANALYSES,  associated with these signals are addressed in LCO 3.3.5.1, LCO, and          *Emergency Core Cooling Systems {ECCS) Instrumentation,* and APPLICABILITY      LCO 3.3.5.2, "Reactor Core Isolation cooling (RCIC) System (continued)      Instrumentation,a and are not included in this LCO.
In genera1, the individual Functions are required to be OPERABLE in MODES 1, 2, and 3 consistent with the Applicability for LCO 3.6.1.l, "Primary Containment.*
Functions that have different Applicabilities are discussed below in the individual Functions discussion.
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
Main Steam Line Isolatton 1.a. Reactor Vessel Water Level-Low Low Low      {Level  Il Low reactor pressure vessel (RPV) water level indicates that the capability to cool, the fuel may be threatened. Should
* RPV water level decrease too far, fuel damage could result.
Therefore, isolation of the MSIVs and other tnterfaces with the reactor vessel occurs to prevent offsite dose limits
                    -from -betng -~xceeded. The Reactor Vessel--Water -Level-Low Low Low {Level 1) Function is one of the many Functions assumed to be OPERABLE and c;apable of providing isolation signa1s .*
The Reactor Vessel Water Level-Low Low Low (Level 1)
Function associated with isolation is assumed in the analysis of the recirculation line break (Ref. I)~ The isolation of the MSLs on Level 1 supports. actions to ensure that offsite dose l 1mits are not exceeded for a OBA *.
Reactot vessel wate~ level Signals are initiated from four level transmitters that sense the difference between the pressure due to a constant colUIITI of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low Low (Level 1) Function are available and are required to be OPERABLE to ensure that no single instrument fatlure can preclude the isolation function.
(continued}
* PBAPS UNIT 2                        B 3.3-146                      Revision No. 0
 
Primary containment Isolation Instrl!lmentation B 3.3.6.1
* BASES APPLICABLE SAFETY ANALYSES.,
LCO, and
: 1. a. Reac:tot Vessel Water Level-Low Low Low CLevel 1)
(continued)
APPLICABILITY    The Reactor Vessel Water Level -Lbw Low Low (Level 1)
Allowable Value is chosen to be the same as the E:CCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the MSLs isolate on a potential loss of coolant accident (LOCA) to prevent offsite doses from exceeding 10 CFR 50.67 limits.
This FunttiOn isolates MSIVs, MSL drains, MSL sample lines and recirculation loop sample line valves.
1.b. Main Steam tine pressure-Low Low MSL pressu~re indicates that there may be a p_robl em with the turbine pressu*re regulation, which could result in a low reactor vessel water level condition and the RPV cooling down more than lOO'F/hr if the pressure loss is allowed to continue. The Main Steam Li'ne Pressure-Low Function is directly assumed 1n the analysis of the pressure regulator failure (Ref. 3). For this event, th~ closure of the MSIVs
**                  ensures that the RPV temperature change limit (lOQ'F/hr) is not reached. In addition, this Function supports actions to ensure that Safety Limit 2.1.1.1 is noj: ~~c;~~-dJ~tf_, ___(This __
F!Jncl'iori~clos*es the-MSIVs *a*urfog-the clepressurization transient in order to maintain reactor steam dome pressue
                    > 700 psia. The MSlV closure results in a scram~ thus reducing reactor power to< 22.6% RTP,)
The MSL low pressure signals are initiated from four transmitters that are connected to the MSL header. The transmitters are arranged such that, even though physicqlly separated from each other, each transmitter is able to detect low MSL pressure. Four channels of Main Steam Line Pressure-Low Fuhction are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Value was selected to be hi.gh enough to prevent excessive RPV depressurization.
The Main Steam Line Pressure-Low Fun<;:tion is only required to be OPERABLE in MODE 1 since this is when the assumed transient can occur (Ref. 1).
This Function isolates MSIVs, MSL drains, MSL sample lines and recirculation loop sample line valves .
* PBAP~ UNIT 2                          8  3.3-147 Ccontinued)
Revision No. 143
 
Primary Containment Isolat1on IAstrumentation B 3 .3. 6 ,'1 BASES
  . APPLICABLE      1.c. Hain steam L1ne fJow-:High SAFETY ANALYSES, LCO, and        Main Steam Line Flow-High is provided to detect a break of APPLICABILITY    the MSL and to initiate closure of the ~SIVs. if the steam (continued)    were all owed to continue fl ow1 ng out of the b.reak, the reactor would depressu.r1ze and the core could uncover. If the RPV water level decreases too far, fuel damage could occur. Therefore, the i&olat1on is initiated on high flow to prevent or minimize core damage. The Main Steam Line Flow-High Function is directly assumed in the analysis of the main steam line break (MSLB) (Ref. 3). The isolat:fon action, along with the scram function of the Reactor Protection System (RPS), ensures that the fuel peak c1adding temperature remains below the l1m1ts of 10 CFR SD.46 and offsfte doses do not exceed the 10 CFR 50.67 11mits.
The MSL flow signals are initiated from 16 transmitters that are connected to the four MSLs. The transmitter~are arranged such that, even though physically separated from each other. all four connected to one MSL would be able to detect the high flow. Four channels of Main Steam Line Flow-High Function for each MSL (two channels per trip system) are available and are required to be OPERABLE so that no single instrument failure will preclude detecting a break 1n any 1nd1v1dual MSL.
The Allowable Value 1s chosen to ensure that off~1te dose limits are not exceeded due to the break.
This Function isolates MS!Vs, MSL drains, MSL sample lines and recirculation loop sample 11ne valves.
L d. Deleted
                                                                          <cooti nued)
* PBAPS UNIT 2                      B 3.3-148  .                Rev1ston No. 134
 
Primary Conta1n~~t Isolation Instrumentation B 3.3.6.1 BASES APPLICABL~      1.e Turbine Bu1Jding Main steam Tunnel Iemperature-H1ah SAFETY ANALYSES, LCD, and        The TUrb1ne Buildir:ig Main Steam Tunnel Temperature Function APPLICABILITY    is provfded to detect a break 1n a ma1n steam l i'ne and provides diversity to the high flow 1nstrumentat1on.
Turb1 ne Bu 11 ding Main Steam Tunnel Temperature s i gna 1 s are initiated from resistance temperature detectors (RTDs) located along the main steam line between the Reactor Building and the turbine. Twelve channels of Turbine Building Mafh Steam Tunnel Temperature-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolat1on function.
The Al1owable Value is chosen to detect a leak equivalent to between 1% and l0% rated steam flow.
This Functiora isolates MSfVs, MSL drains, MSL sample lines
* and recirculation loop sample line valves .
1.f, Reactor Bu1ld1na Maio Steam Tunnel Temperature-High The Reactor Building Main Steam Tunnel Temperature Function fs prov1ded to detect a break in a main steam 11ne and prov1des d1vers1ty to the high flow instrumentation.
Reactor Building Main Steam Tunnel Temperature signals are initiated f'rom resistance temperature detectors (RTDs) located in the Ma1n Steam L1ne Tunnel ventilation exhaust duct. Four channels of Reactor Building Main Steam Tunnel remperature-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude t~e isolation function.
Ccont1 nued 2 PBAPS UNIT 2                        B 3.3-149                  Revision No. 134
 
Primary Containment Isolation Instrumentation B 3.3.6 . 1
* BASES APPLICABLE SAF=ETY ANALYSES, 1.f Reactor Building Main Steam Tunnel Temperature-High (continued)
LC0,, and APPLICABILITY    The Allowable Value is chosen to detect a leak equivalent to between 1% and 10% rated steam flow.
This Function isolates HSIVs; MSL drains, MSL sample lines aod recirculation 1oop s,ample line vaTves.
Primary Containment Isolation 2.a. Reactor Vessel Water Level-LOW (Level 3)
Low RPV wat,ar level -f ndi cates that the capability to cool the fuel may be threatened. The valves whose penetrations communicate With the primary containment are isolated to limit the release of fission products. The isolation of the primary containment on Level 3 supports actions to ensure that offsite dose limits of 10 CFR 50.67 are not exceeded.
(continued)
* PBAPS UNIT 2                      B 3.3-149a                    Revision No. 75
 
Pr1mary Conta1nment Isolation Instrumentation B 3.3.6.1
* BASES APPLICABLE SAFETY ANALYSES, LCO, and 2.a. Reactor Vessel Water Level-Low (Level 3)
The Reactor Vessel Water Level -Low (Level 3) Function (cont1nued)
APPLICABILITY    assoc1ated with 1solation is impl1c1tly assumed 1n the UFSAR analysis as these leakage paths are assumed to be isolated post LOCA.
Reactor Vessel Water Level -Low (Level 3) -s1gnals are initiated from l,evel transm1tters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the a6tual water level (variable leg) i"n the vessel . Four channels of Reactor Vessel Water Level-Low (Level 3) Function are available and are required to be OPERABLE to ensure that no single instrument fa11ure can preqlude the isolation function.
The Reactor Vessel_ Water Level - Low ( Level 3) A11 owab le Value was chosen to be the same as the RPS Level 3 scram Allowable Value (LCO 3.3.1.1), s1nce 1solation of these valves ts not critical to orderly plant shutdown .
* This Function isolates the Group Il(A) valves 11sted in Reference 1 W1th the exception of RWCU isolation valves and RflR shutdown cooling pump suct1on valves which-are addressed 1n J=UnCti onS 5. c and 6. b*, r*es*pect1 vel y.
2.b. Drywall Pressure-High H1gh drywell pressure can indicate a break in the RCPB inside the primary containment. The isolation of some of the primary containment isolation valves on high drywall pressure supports actions to ensure that offsite dose limits of 10 CFR 50. 67 are not exceeded. The Drywall Pressure-H1 gh Function, associated with i sol ati on of the primary containment,. is implicitly assumed in the UFSAR acc1dent analysis as these leakage paths are assumed to be 1solated post LOCA.
High drywel l pressure signals are i nHi ated from pressur.e transmitters that sense the pressure in the dryWe11. Four channels of Drywall Pressure-High are available and are required to be OPERABLE to ensure that no single instrument failure can preclude ths isolation function.
(continued)
* PBAPS UNIT 2                        B 3.3-150                      Revision No. 75
 
Primary Containment Isolation Instrumentation B 3.3.6.1
* BASES APPLICABLE          2.b. Dr.vwell Pressure-High (continued)
SAFITT ANALYSES, LCO, and            The Allowable Value was selected to be the same as the ECCS APPLICABI LIT't    Drywell Pressure.-High Allowable Value (LCO 3.3.5.1), since thiS may be indicative of a LOCA inside. primary containment.
This Function isolates the Group ll(B) valves listed in Refere nee 1 .
2.c. Majn Stack Monitor Radiation-High Hain stack monitar radiation is an indication that the release of radioactive material may exceed established limits. Therefore, when Main Stack Monitor Radiation-High is detected when there 1s fl ow through the Standby Gas Treatment System, an isolation of primary containment purge supply and exhaust penetrations is initiated to limit the release of fission products. However, this Function is not assumed in any accident or transient analysis in the UFSAR because other leakage paths (e.g4, MS!Vs) are more. l trniting.
The drywell radiation signals are initiated from rad'iation
* detectors that isokinetically sample the main stack utilizing sample pumps. Two channels of Main Stack
___ Radiati_'?Jl::_.Hig_h_functio_n -~r~~~va_iJable__~n~_are re9._'!.ire.c:J to __
be OPERABLE to ensure tnat no s'lngle. 1nstrumen1: ra1lure can- - -
preclude the isolation function.
The Allowable Value is set below the maximum. allowable release limit in accordance with the Offsite Dose Calculation Manual {ODCH).
This Function isolates the containment vent and purge valves and other Gnrnp IIl{E) valves listed in Reference 1.
2.d., 2.e. Reactor Building Ventilation and Refueling Floor VenUJation Exhaust Radiation-High High secondary containment exhaust radiation is an indication of possible gross failure of the fuel cladding.
The release may nave originated from the primary containment due to a break in the RCPB. When Reactor Building or Refueling Floor Ventilation Exhaust Radiation-High is detected, the affected ventilation pathway and primary (continued)
** PBAPS UNIT 2                              B 3.3-151                        Revision No. 20
 
Primary Containment Isolation Instrumentation
                                                                            . B 3.3.6.1
* BASES
  .APPLICABLE      2,d., 2.e. Reactor BuUdina Yentnation and Refueling Floor SAFETY ANALYSES, Ventilation Exhaust Radiation-High (continued)
LCO, and APPLICABILITY    containment purge supply and exhaust valves are, isolated to Hmi t the re 1ease of f1 ss ion products. Add :it i ona11 y, Ventilation Exhaust Radiation-High Function initiates Standby Gas Treatment System.
The Ventilation Exhaust Radiation-High signals are
* initiated from radiation detectors that are located on the ventilation exhaust piping cming from the reactor building and the refueling floor zones, respective 1y The ~ 1gna l from each detector is input to an individual monitor whose trip outputs are assigned to an isolation channel. Four channels of Reactor Building Vent 11 at 1on Exhaust-High Function and four channels of Refue.ling Floor Ventilation Exhaust-High Function are available and are required to be OPERABLE to ensure ,that no single instrument failure can preclude the isolation function.
The Allowable Values are chosen to promptly detect gross fan ure of the fuel cladding during a refue l:i ng ace ident *
* These Functions isolate the Group III(C) and III(B) valves 1i sted i.n Reference 1.
High Pressure coolant Injection and Reactor Core Isolation Cooling Systems Isolation                    '
3.a,, 3.b *. , 4.a., 4.b. HPCI and RCIC Steam Une Flow-H,gh and Time Delay Relays Steam Line Flow-High Functions are provided to detect a break of the RCIC or HPCI steu lines and initiate closure of the steam line isolation valves of the appropriate system. lf the steam is allowed to continue flowing out of the break, the reactor will depressurize and the core can uncover. Therefore, the isolations are initiated on high flow to prevent or minimize core damage. The isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Specific credit fQr these .Functions is not assumed in any UFSAR accident analyses since the (continued)
* PBAPS UNIT 2                          B 3.3-152                      Revision No. o
 
Primary Containment Isolation Instrumentation B 3.3.6.1
* BASES APPLICABLE SAFETY ANALYSES, LCO, and 3.a .. 3.b., 4.a., 4.b. HPCI and RCIC Steam Line Flow-High and Time Delay Relays (.continued)
APPLICABILITY    bounding analysis 1s performed for large breaks such as recircnlation and MSL breaks. However, these instruments prevent the RCIC or HPCI steam line breaks from becoming bounding.
The HPCI and RCIC Steam Line Flow-High si.gnals are initiated from transmitters (two for HPCI and two for RCIC) that are c~nnected to the system steam lines. A time delay is provided to prevent isolation due to high flow transients during startup with one Time Delay Relay channel associated with each Steam Line now-High channel. Two channels of both HPCI and RCIC Ste8111 Line Flow--High Functions and the associated Time Delay Relays are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Values for Steam Line Flow.-High Function and associated Time Delay Relay Function are chosen to be low enough to ensure that the trip occurs to maintain the MSLB
* event as the bounding event
* These Functions isolate the associated HPCI and RCIC steam supply *and -turbine-exhaust va-lves --cand- pump--suct-ion--val ves.--- .-~--
                  ~.c., 4,c. HPCI and RCIC steam supply Line Pressure-Low Low MSL pressure indicates that the pressure of the steam in the. HPCI or RCIC turbine may be too low to continue operation of the associated system's turbine. These isolatfons prevent radioactive gases and steam from escaping through the pump shaft seals into the reactor bui.lding but are primarily for equiJ>'IEmt protection and are al so assumed for long term contatmnent isolation. However, they also provide a dive:se si~nal to incliicate a possible. system break. These rnstruments are included in Technical Specifi,cations (TS) because of the potential for risk due to possible failure of the instruments preventing HPCI and RCIC initiations (Ref. 4).
The HPCI and RCIC Steam Supply Line Pressure-tow signals are initiated from tranSJRitters (four for HPCI and four for RCIC) that are connec:ted to the system steam line. Four
{continued)
PBAPS UNIT 2                        B 3.3-153                        Revision No. O
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES          .......,.
APPLICABLE                3. c., 4, c, HPC I and RCIC steam syopJ v u ne  Pressure-Low SAFETY ANALYSES,          (continued)
LCO, and APPLICABILITY              channels of both HPCI and RCIC Steam Supply Line Pressure-Low Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Values are selected to be high enough to prevent damage to the system's turbine.
These Functions isolate the associated HPCI and RCIC steam supply and turbine exhaust valves and pump suction valves.
3,d., 4.d. PrvweJl Pressure-High <Vacuum Breakers>
High drywall pressure can indicate a break in the RCPB. The HPCI and RCIC isolation of the turbine exhaust vacuum bteakers is provided to prevent c01111unication with the drywell when high drywell pressure exists. The HPCI and RClC turbine exhaust vacuwn breaker isolation occurs fo'1lowing a pennissive fr011 the associated Steam Supply Line Pressure-Low Function which indicates that the system is no longer required or capable of performing coolant injection.
The isolation of the l:IPCI and RCIC turbine exhaust vacuum breake.rs--by DryweH *Pressure---High is-indirectly-assumed -in------ ---
the UFSAR accident analysis because the turbine exhaust leakage path is not assumed to contribute to offsite doses.
High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Four
                            ,channels for both HPCI and RCIC Drywell Pressure-1-ligh (Vacuum Breakers) Functions are available and are required
              ~-          tQ be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Value was selected to be the sarae as the ECCS Drywell Pressure-High Allowable Value (LCO 3.3.5,1), since this is indicative of a LOCA inside primary containment.
This Function isolates the associated HPCl and RCIC vacuum relief valves and test retur:n line valves.
{continued).
* PBAPS UNIT 2                                B 3.3-154                      Revision No. 0
 
Primary Containment Isolation Instrumentation B 3.3.6.1
* BASES
  ---------------~~----------------
APPLICABLE:        3.e.i 4.e. HPCI and RCIC Compartment and Steam Line Area SAFETY ANALYSES, Temperature - High LCO, and APPLICABILITY      HPCI and RCIC Compartment and Steam Line Area temperatures (continued)      are provided to detect a leak from the associated system steam piping. The isolation occurs when a very small leak has occurred and is diverse to the high flow
* instrumentation. If the small leak is allowed to continue without i sol at ion, offs i te dose l i,mi ts may be reached.
These Functions are Aot assumed in any UFSAR transient or accident analysis, since bounding analyses are performed for large breaks such as recirculation or MSt breaks.
HPCI and RCIC Compartment-and Steam Line Area Temperature-High signals are. initiated from resistance temperature detectors (RTDs) that a.re appropriately located to protect the system that is being monitored. The HPCI and RCJC Compartment and Steam Line Area Temperature--High Functions each use 16 temperature channels. Sixteen channels fo,r each HPCI and RCIC Compa.rtment and Steam Line Area Temperature-High Function are available and are
* required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
                  *-*nu~~Anowable Values-are set low*enough-to detect-a: lear.-*-
These Functions isolate the associated HPCI and RCIC steam supply and turbiAe exhaust valves a:nd pump suction valves.
Reactor Water Cleanup (RWCU) System Isolation 5.a. RWCU Flow-Hi,qh The high flow signal is provided to detect a break in the RWCU System. Should the reactor coolaAt continue to flow out of the break, offsite dose limits may be exceeded.
Therefore, isolation of the RWCU System is initiated when high RWCU flow is sensed to prevent exceeding offsite doses.
This Function is not assumed in any UFSAR transient or accident analysis, since bounding analyses are performed for large breaks such as MSLBs.
(continued)
* PBAPS UNIT 2                            B 3.3-155                        Revision No. 32
 
Pr1ma.ry Containment lsolation Instrumentation B 3.3.6.1
* BASES APPLICABLE      5.a. RWCU F1ow-4iigh  (continued)
SAFETY ANALYSES, LCO, and        The high RWCU flow signals are initiated from transmitters APPLICABILITY    that are connected to the pump suction line of the RWCU System. Two channels of RWCU Flow-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The RWCU Flow-High Allowable Value ensures that a break of the RWCU piping is detected.
This Function isolates the inboard and outboard RWCU pump suction penetration and the outboard valve at the RWCU connection to reactor feedwater.
5.b. Standby Liquid Control (SLC) System foitiat1on The isolation of the RWCU System is required when the SLC System has been initiated to prevent dilution and removal of the boron solution by the RWCU System (Ref. 5). SLC System initiation signals are initiated from the remote SLC System start switch ..
* There is,n9.Allowable Value associated with this Function since the channels are mechanically actuated based solely on the position of the SLC System i niti ati on switch.
For reactivity insertion accidents, two channels of the SLC System Initiation Function are available and are required to be OPERABLE in MODES 1 and 2, since these are the only HODES where the reactor can be critical. In addition, for accidents involving significant fission product releases, both channels are required to be OPERABLE in MODES 1, 2, and 3. The SLC System is designed to maintain suppression pool pH at or above 7 following a LOCA to ensure that sufficient iodine will be retained in the suppression pool water. These MODES are consistent with the Applicability for the SLC System (LCO 3.1.7).
This Function isolates the inboard and outboard RWCU pump suction penetration and the outboard valve at the RWCU connection to reactor feedwater.
5.c. Reactor Vessel Water Level~Low (Level 3)
Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore. isolation of some interfaces with the reactor vessel occurs to isolate the potential sources of a break. The i sol ati.on of the RWCU System on Level 3 s.upports actions to ensure that the fuel (continued)
PBAPS UNIT 2                      B 3.3-156                    Revision No. 75
 
Primary Containment IsolatJon Instrumentation
* B 3.3.6.1 BASES APPLICABLE      5.c. Reactor Vessel Water Level-Low Cleve) 3> (continued)
SAFEiY ANALYSES.
LCO, and        peak cladding temperature rematns below the limits of APPLICABILITY    10 CFR 50.46. The Reactor Vessel Water Level-Low (Leval 3)
Fur:iction associated w1th RWGU isolation 1s not d1rect1y assumed 1n the UFSAR safety analyses because the RWCU System line break 1s bounded by breaks of larger systems (recirculation and MSL breaks are more 11mit1ng).
Reactor Vessel Water Level - Low CLevel 3) s 1gna 1 s a re initiated from four level transm1tters that sense the dffference between the pressure due to a constant co~umn of water (reference leg) and the pressure due to the actual water level (var1ab~e leg) 1n the vessel .. Four channels of Reactor Vessel Water Level ~Low (Level 3) Funct1on are available and are req~ired to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Reactor Vessel Water Level -Low (Level 3) Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level-Low (Level 3) Allowable Value (LCD 3.3.1.1),
since the capability to cool the fuel may be threatened .
This Function isolates the 1nboard and outboard RWCU suction penetr-ati on and the outboar-d -valve- at the RWCU connect-fan to -
reactor feedwater.
Shutdown CooJ1ng System Isolat1oo 6.a,    Reactor Press.uce::fl1gh The Reactor Pressijre-H1gh Funct1on is provided to isolate t~e shutaown cooling portion of the Residual Heat Removal (RHR) System. Th1s Funct1on is provided only for equipment protecti ori to prevent an 1ntersystem LOCA scenario, and credit for the Function is not assumed in the accident or transient analysis in the UFSAR.
The Reactor Pressure-High signals are initiated from two relays driven by trip unfts associated with pressure transmitters that sense RP~ pressure at different taps on the RPV. Two channels of Reactor Pressure-High Function are available and are required to be OPERABLE to ensure that no sfngle instrument failure can preclude the tsolation function. The Function is only required to be OPERABLE 1n (continued)
* PBAPS UNIT 2                        B 3.3-157                    Revision No.135
 
Pritnar.y Containment .Isolation Instrumentation B 3,.3.6.1
* BASES
    ----------------------------------~-
APPLICABLE      6.a. Reactor Pressure-High          (continued)
SAFETY ANALYSES, LCO, and      . MODES 1, 2, and 3, since these are the only MODES in wtii~h APPLICABILITY    the reactor can be pressurized; thus, equipment protection is needed. The Allowable Value was chosen to be low enough to protect the system equipment from overpressurization.
This Function isolate~ both RHR shutdown cooling pump suction valves.
6,b. Reactor Vessel water Level-Low <Level 3l Low RPV water level indicates that the cap~bility to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, iso1ation of some reactor vessel interfaces occurs to begin isolating the potential sources of a break. The Reactor Vessel Water Level-Low (Level 3} Function associa.te'CJ with RHR Shutdown Cooling System isolation is not directly assumed in safety analyses because a break of the RHR Shutdown Cooling System is bounded by break.s of the recirculation and MSL. Jhe. RHR Shutaown Cooling System isolation on Level 3 supports
* actions to ensure that the RPV water level does not drop below the top of the active fuel during a vessel draindown event caused by a leak (e.g., pipe break or inadvertent valve opening) in the RHR Shutdown Cooling System.
Reactor V1;ssel Water Level-Low (Level 3) signals are initiated from four leve1 transmitters tflat sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels (two channels per trip system) of the Reactor Vessel Water Leve l - Low ( Lev e 1 3 ) Fu L1 ct i on a re a va il a bJ e and a re re qui red to be OPERABLE to ensure that no single instrument failure can preclude the isolation function .
* PBAPS UN IT 2                          B 3.3-158                              Revision No. 145
 
Primary Containment Isolation Instrumentation B 3.3.6.1
* BASES APP LI CABLE SAFETY ANALYSES, LCO, and 6,b. Reactor Vessel Water Level-Low (Level 32 The Reactor Vessel Water Level-Low (Level 3) Allowable (continued)
APP LI CAB I LI TY Value was chosen to be the same as the RPS Reactor Vessel Water Level-Low (Level 3) Al1owable Value (LCD 3.3.1.1),
since the capability to cool the fuel may be threatened.
The Reactor Vessel Water Level - Low CLevel 3) Function is only required to be OPERABLE in MODE 3, to prevent this potential flow path from lowering the reactor vessel level to the top of the fuel. In MODES 1 and 2, another i sol ati on (i.e., Reactor Pressure-High) and administrative controls ensure that this flow path remains isolated to prevent unexpected loss of inventory via this flow path.
This Function isolates both RHR shutdown cooling pump suction valves.
Feedwater Recirculation Isolation 7.a, Reactor Pressure-High The Reactor Pressure-High Function is provided to isolate the feedwater recirculation line. This interlock is prov,ded only for equipment protection to prevent ah intersystew LOCA scenario, and credit for the interlock is not ~ssumed in the accident or transi~~t cinalysis in the UFSAR.
The Reactor Pressure~High s1gnals are initiated from four transmitters thH a re connected to d tfferent taps on the RPV. Four channels of Reactor Pressure-High Function a re available and are required to be OPERABLE to e~sure that no single instrument failure can preclude the isolation fun ct i on . The Fun ct i on i s on l y re q ui red to be OPERAS LE i n MODES 1, 2, and 3, si nee these a re the only MODES in which the reactor can be pressurized; thus, equipment protection is needed. The Allowable Value was chosen to be low enough to prQtect the system equipment from overpressurization.
This Function isolates the feedwater recirculation valves.
Traversing Incore    Probe System Isolation a.a,    Reactor Vessel Water Level-Low, Level 3 Low RPV water level indicates t_hat the capability to cool the fuel may be threatened. The valves whose penetrations communicate with the primary containment are isolated to
* PBAPS UNIT 2 (continued)
Revisi*on No. 145
 
Primary Containment Isolation Instrumentation B 3.3.6.1
* BASES APPLICABLE SAFETY ANALYSES, LCO, and APP LI GABI LITY 8.a. Reactor Vessel Water Level-Low. Level 3 (continued) limit the re.Tease of ftssion products. The isolation of the primary containment on Level 3 supports actions to ensure that (continued)      offsite dose limits of 10 CFR 100 are not exceeded. The Reactor Vessel Water Level-Low. Level 3 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated po.st LOCA.
Reactor Ve.ssl Wa.ter Level-Low, Level 3 signals are initiated from level transmitters that sense the diffe,rence between the pressute due ta a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the-vessel. 1wo channels of Reactor Vessel Water Level-Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can initiat~ an inadvertent isolati,on actuation. The isolation function is ensured by the manual shear valve in each penetration.
The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the S'ame as the RPS Level 3 scram Allowable Value (LCD 3.3.1,1), since isolation of these valves is not critical to orderly plant shutdown .
* Tbis Function isolates the Group II(~) TIP valves.
                    --*s~b~  rywe*11**-F,-ressure:::Bf6b -
High drywell pres.sure can indicate a break in the RCPB inside the primary containment. The isolation of some of the primary containment isolation valves on high drywell pressure supports actions to ensure that offsite dose limits of 10 CFR 100 are not exceeded. The Drywell Pressure-High Function, associated with isol~tion of the primary containment, is implicitly assumed in the FSAR ac~ident analysis as these leakage paths are assumed to be isolated post LOCA.
High dryw-ell pressure signals a.re 'initiated from pressure transmitters that sense the pressure in the drywell. Two channels of Drywell Pressure-High per Function are available and are required to be OPERABLE to ensure that no single instrument failure can initiate an inadvertent actuation. The isolation function is ensured by the manual shear valve in eaeh penetration.
The allowable Value was selected to be the same as the ECCS Otywell Pressure-High Allowable Value (LGO 3.3.5.1), since this may be indicative of a LOCA inside primary containment.
* PBAPS UN IT 2 This_ Function isolates the Group II(D) TIP valves .
B 3.3-1~9a
{con ti nue.d)
Revision No. 57
 
Primary Containment Isolation Instrumentatton B 3,3.6.1
* BASES ACTIONS (continued)
The ACTIONS are modified by two Notes. Note 1 a1lows penetration flow path(s) to be unisolated intermittently under administrative controls. These cohtrols consist of stati.oning a dedicated operator at the controls of the valve, who is in continuous communication with th~ control room. In this way, the penetration can be rapidly isolated when a need for primary coAtainment isolation is indicated. Note 2 has been provided to modify the ACTIONS related to primary containment isolation instrumentation channels. Section 1.3, Completion Times, specifies that once* a Condition has been entered, s.ubsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition, Section 1. 3 a1so specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion rimes based an initial entry into the Condition.
However, the Required Actions for inoperable primary containment isolation instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable primary containment isolation instrumentation channel .
* Because of the diversity of sensors avai1able to provide isolatio~ signals and the redundancy of the isolation design, an allowable out of service time of 12 hours for Functions l.d, 2.a, and 2.b and 24 hours for Functions other than Functions 1.d, 2.a, and 2.b has been shown to be acceptable (Refs. 6 and 7) to permit restoration of any inoperable channel to OPERABLE status. This out of service time is only acceptable provided the associated Function is still maintaining isolation capability (refer to Required Action B.1 Bases). If the inoperable channel cannot be restored to OPERABLE status within th.e a11 owabl e out of service time, the channel must be placed in the tripped condition per Required Action A.1. Placing the inoperable channel in trip would conservatively compensate for the irroperability, restore capability to accorranodate a ::;fogle failure, and allow operation to continue with no further restrictions. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an isolation),
Condition C must be entered and its Required Action taken.
(continued)
PBAPS UNIT 2                          B 3.3-160                        Revision No. 57
 
PrJ.mary Contaihment Isolation Inst'rumentatioh 13 3.3,6.1
* BASES AC'J'IONS (continued)
B.1 Required Action B.1 is intendt;d to ensure that appropriate actions are taRen if multiple, inoperable, untripped channels within the same Function result in redundant isolation capability being lost fo.r,the associated penetration flow path(s}. For those MSL, Primary Containment:, HPCI, RCIC, RWCU, SDC, and ,Feedw<;1.ter.
Recirculation Isolation Functions, where actuation of both trip systems is needed to isolate a penetration,. the Ftihctions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in tr.ip (or the associated trip system in trip), such that both trip systems will generate a trip signal from the given Function 011; a valid signal.              For those Primary Containment, HPCI, RCIC, RWCU, and SDC isolation functions, where actuation of one trip system is needed to isolate a penetration, the Function$ are considered to be maintaining isolation capapility when sufficient channels are OPERABLE or. in trip,,
such that one trip system will generate a. tr.ip signal from the given function on a valid signal. This ensures that at least one of th!;! PCIVs :1,n the associated penetration flow path can receive an isolation .signal from the given E\lnction- For all Functions e}{cept 1.c, 1.e,. 2.c, 3.a, 3.b,
                  ,_ 3-:-e,-- 4-:-a;--1-:b-,- '1 :e,. -5 :a;-s. b~ ahd-o :a, -thTs"""would r-equlre--
both trip systems to have one channel OPERABLE or in trip.
F'o.r Function 1. c, this would require. both trip systems to have one ~hannel, as$ociated with each MSL, OPERABLE or in trip. For F1.J.nctions 1. e, 3. e and 4 .. e, each Function consists of channels that monlto:r* several locations within a given area (e.g., different locations wi;thin the Turbine Building main steam tunnel area). Therefore, this would r.e@ire both trip systems to have one channel p;!r location OPERABLE or in trip. Fo.t ];:Unctions 2.c, 3.a, 3.b, 4.a:, 4.,b, 5.a, and 6.a, this would require one trip system to hav~ one channel OPERABLE or in trip.
The Completion Time is intended to allow the operator t.:l.me to evaluate and r~pair any discovered inoperabilities. '.I'he 1 hour Completion Time -is acceptable because it minimizes risk while allowing time for; restoration or tripping o!E channels.
( continued.)
* PBAPS UNIT 2                                  B 3.,3-161                          Revision No. 48
 
Primary' Containment I sol ati on Instrum-entati on B 3.3.6.l BASES ACTIONS        1l...d  (continued)
Entry into Condition Band Required.Action B.1 may be necessary to avoid an MSL isolation transient resulting from a temporary loss of ventilation in the main steam line. tunnel area. As allowed by LCO 3.0.2 (and discussed in the Bases of LCO 3.0.2.), the plant may intentionally enter this Condftion to avoid an MSL fsolation trans1ent following the loss of ventilation flow, and then raise the setpoints for the Main Steam Tunnel Temperature-High Function to 250&deg;F causing all channels of Mair:i Steam Tunnel Temperature-High Function to be inoperable.
However,, during the period that multiple Main Steam Tunnel Temperature-High Function channels are inoperable due to this intentional actior:i, ari additional compensatory measure. is deemed necessary and shall be taken: an operator shall observe control room indications of the duct temperature so the main steam line isolation valves may be promptly closed in the event of a rapid increase in MSL tunnel temperature indicative of a steam line break.
Ll
_ _RegyJ,r:_ed AGtJ on C._1 _d j ff~t_&sect;__ e_nt_ry __i_n_t:9 _ihe _c!_pp rQprjg_ t~-
Cond it ion referenced in Table 3.3.6.1-1. The applicable Condition .specified in Table 3.3.6.1-1 is Function and MODE or other specified condition dependent and may change as the Required Action of a previous Condition is completed. Each time an inoperable channe1 has not met any Required Action of Condition A or Band the associated Completion Time has expired, Condi ti on C will be enhred for that channel and provides for transfer to the approp,ri at-e subsequent C0nditi on.
D.1. D.2.1. and D.2.2 If the channel is not restored to OPERABLE status or placed in trip Within the allowed Completion Time, the plant must be pl aced in a MODE or other spec Hied condHi on in which the LCO does not apply. This is done by placing the plant in at least MODE 3 within 12 hours* and in MODE 4 within 36 hours (Required Actions 0.2.1 and 0.2.2). Alternately, the associated MSLs may be isolated (Required Action D.1),
* PBAPS UNii 2                        B 3.3-162                                      Revision No. 45
 
Primary Containment Isolation Instrumentation B 3.3.6.1
* BASES ACTIONS        D.l, D.2.1. and D.2.2 (continued) and, if allowed (i.e. 1 plant safety .analysis allows operation with an MSL isolated), operation with that MSL isolated may continue. Isolating the affected MSL accomplishes the safety function of the inoperable channel.
The Completion Ti.mes are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without cha11 eng i ng pl ant systems.
L.l If the channel is not restored to OPERABLE status or placed in trip within the allowed Completi-0n Time, the plant must be placed in a. MOOE or other specified condition in which the LCO does not app1'y. This is done by placing the plant in at least MODE 2 within 6 hours.
The allowed Completion Time of 6 hours is reasonable, based on operating experience, to reach MODE 2 from full power conditions in an orderly manner and without challenging plant systems.
* F.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operations may continue if the affected penetration flow path(s.) is isolated. Isolating the affected penetration flow path(s) accomplishes the safety function of the inoperable channels.
Alternately, if it is not desired to tso1ate the affected
* penetration flow path(s) (e.g., as in the case where isolating the penetration flow path(s) could result in a reactor scram), Condition G must be entered and its Required Actions taken. The l hour Completion Time is acceptable because 1t minimizes risk while allowing sufficient time for plant operations personnel to isolate the affected penetration flow path(s). *.
{continued}
PBAPS UNIT 2                      B 3 .3-163                    Revision No. O
 
Primary Containment Isolation Instrumentation.
B 3.3.6.1
* BASES ACTIONS        G,I and G.2 (continued)
If the channel 'ls not 'restored to OPERABLE status or placed in trip within the allowed Completfon Time, or the Required Action of Condftion Fis not met and the associated' Completion Time has expired, the plant must be placed in a MODE or other specffied condition in which the LCO does not apply. This is done by placing the plant in at least MOOE 3 within 12 ho1.1rs and in MOOE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required pl ant conditions from fU-11 power conditions in an orderly anner and without challenging plant systems.
H.1 and H,2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated SLC subsystem(s) 1s declared inoperable or the RWCU System is isolated. Since this Function is re(luired' to ensure that the SLC System perfoms its intended function, sufficient remedial measures are provided by declJring the associated SLC subsystems inoperable or isolating the RWCU_System.
The-I hour--Go111Pl'etion-Time -is acceptable because -tt*- - -- --
minimizes risk while allowing sufficient time for personnel to isolate the RWCU System.
1.1 and 1.2 If the channel is not restored to OPERABLE status or placed in trip withi.n. the allowed Completion Time, the associated penetration flow path should be closed. However, if the shutdown. cooling function is needed to provide core cooling, these Required Actions allow the penetration flow path to remain unisolated provided acti,on is irnnediately initiated to restore the channel to OPERABLE status or to isolate the
                .RHR Shutdown Cooling System (i.e., provide alternate decay heat removal capabilities so the penetration flow path can be isolated). Actions must continue until the channel is restored to OPERABLE status or the RHR Shutdown Cooling Sy,stem is isolated.
{continued)
* PBAPS UNIT 2                      B 3.3-164                      Revision No. 0
 
Primary Containment Isolation Instrumentation B 3.3.6.1
* BASES  (continued)
SURVEILLANCE REQUIREMENTS
                      .As noted at the beginning of the SRs, the .SRs for each Primary Containment Isolation instrumentation Function are found in the SRs column of Table 3.3.6.1-1.
The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour al 1 owance, the channel must be returned to OPERABLE status or the applic:.a,ble Condition entered and Required Actions taken. Th1s Note is based on the reliability analysis (Refs. 6 and 7) assumption of the average time r~quired to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the PCIVs will isolate the penetration flow path(s) when necessary.
SR  3,3,6.1.l
* Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL l
_CHECK _1 s_J1o_i:_m 9 l_l_Y._ a_~Q_mpar_i so_ll c9J, the. _p~r_ameter J_ndi cated_ o_n ____ _
one channel t~ a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.
Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or of something e~en more serious, A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continuei to operate properly between each CHANNEL CALIBRATION.
Agreement criteri.a are determined by thie pl ant staff based on a combination of the channel instrument uncertafnties, including indication and readability. If a channel is outside the crfterfa, it may be an indication that the instrument h.as drifted outside its limit.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequentl checks of channels during normal operational use of the displays associated with the channels required by the LCO .
* PBAPS UN IT 2                                B  3.3-165                            Revision No. 86
 
Primary Centa1nment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE    SR    3.3,6.1.2 R~QU IRtMtNTS (continued)  A CHANNEL i='UNClIONAL TEST is performed on e-ach requfred channel to ensure that the enttre channel will perform the intended function. Any setpo1ot adjustment shall be consistent with the assumptions of the current plant speciftc setpoitlt methodology. For Eunction 1.e, l.f, 3.e, and 4.e channels, verification that trip settings are less than or equal to the spec.Hied Allowable Value dur1ng the CHANNEL FUNCTIONAL TEST 1s not requit~d since the installed indication instrumentation does not provide accurate indication of the trip setting. This 1s considered acceptable since the magnitude of drift assumed in the setpoint calc.ulat1o.n is based on a 24 month caltbration 1nterval .
The Surveillance Frequency ts controlled under ttre Surveillance Frequency Control Program.
SR 3.3.6,1,3. SR 3,3i&,l,4, and SR 3.3,6.1.5 CSR 3.3.6.1,6 Deleted}
* A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel
                ,,responds -to- the -measured -paramete.r within -the -necessary - -
range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations, consistent with the assumptions of t'he current setpoint methodology.
Specific to Main Steam Line Pressure-Low (Technical Specificattoa Table 3.3.6.1-1, Funct1on 1.b) and the Ma1n Steam L1ne Flow-H1gh (Technical Specif1catfon Table 3.3.6,l-1, function l.c), there is a plant specific program which verifies that this instrument channel functions as required by verifying the as-left and as-found settings are consistent with t~ose established by the setpo1nt methodo1ogy.
Ccoratjnued>
* PBAPS UNIT 2                      B 3.:3-166                    Revision No. 134
 
Primary Containment Isolat1on Instrumentation B 3.3.6.1
* BASES SURVEl LLANCE REQUIREMENTS SR 3.3,6.1.3. SR 3.3.6,1.4, SR 3.3,6,1,5, and SR 3.3.6,1,6 (continued)
The Surveillance Frequency is controlled under the Surve111 ance Frequency Control Program.
SR 3:,3.6.1.7 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation lO'gic for a spe,cific ch.annel. The system functional testing performed on PCIVs tn LCO 3.6.1.3 overlaps this Surveillance to provide complete testing of the assumed safety function.
The Surveillance Frequency is cofitrolled under the Surveillance Frequency Control Program.
REFERENCES    1. UfSAR, Section 7.3.
: 2. NRC Safety Evaluation Report for Amendment Numbers 156 and 158 to Faci l it.Y Op-era ting License Numbers DPR-44 and DPR-56, Peach Bottom Atomic Power Station, Unit Nos: 2 and -3; September 7, 1990.
: 3. UFSAR, Chapter 14.
: 4. NED0-31466, "Technical Specification Screening Criteria Application and Risk Assessment,"
November 1987.
: 5. UFSAR, Section 4.9.3 .
* PBAPS UN IT 2                    B 3.3-167                      Revision No. 114
 
Primary Containment Jsolatioh Instrumentation B 3.3.6.1
* BASES
: 6. NEDC ~31677P-A, "Techn1 cal Specifi cat ton Improvement Analysts for BWR Isolation Actuation Instrumentation,"
July 1990.
: 7. NEDC-3'0851P-A Supplement 2, "Techni.ca1 Spec.iflcations Improvement Analysis for BWR IsolatioA Instrumentation Common to RPS and ECCS Instrumentation," March 1989.
: a. NEDC-33~73P, "Safety Analysis Report for Peach Bottom Atomic Power Station, Units 2 and 3, Thermal Power Optimization," Revision O.
PBAPS UNIT 2                B 3.3-168                    Revision No. 143
 
Secondary Containment Isolation Instrumentation B 3.3.6.2
* - B 3 .3 INSTRUMENTATION B 3.3.6.2 Secondary Contatnment Isolation Instrumentation BASES BACKGROUND        The secondary containment isolation instrumentation automatically initiates closure of appropriate secondary containment isolation valves {SCIVs) and starts the Standby Gas Treatment {SGT) System. The function of these systems, i.n combination with other accident mitigation systems, is to limit fission product rel ease during and f o11 owing postulated Design Basis Accidents (DBAs) {Ref. 1).
Secondary containment isolation and establishment of vacuum with the SGT System within the required time limits ensures that fission products that leak from primary containment following a OBA, or are released outside primary containment, or are released during certain operations when primary containment is not required to be OPERABLE are maintained ~ithin applicable limits.
The isolation instrumentation includes the sensors, relays,
* and switches that are necessary to cause initiation of secondary containment isolation. Most channels include electronic equipment {e.g., trip units) that compares measured i npot- -signa1s ~with ~re",;.estatrl i'she-a- -setpotnts-. *-When -
the setpoi nt is exceeded, the channe1 output relay actuates,.
which then outputs a secondary containment isolation signal to the isolation logic. Functional diversity is provided by monitoring a wide range of independent parameters. The input parameters to the isolation logic are (1) reactor vessel water level, {2) drywell pressure, {3) reactor building ventilation exhaust high radiation, and
{4) refueling floor ventilation exhaust high radiation.
Redundant sensor input signals from each parameter are provided for initiation of isolation.
The outputs of the channels are arranged in a one-out-of-two taken twice logic. Automatic isolation valves {dampers) isolate and SGT subsystems start when both trip systems are in trip. Operation of both trip systems is required to.
isolate the secondary containment and provide for the necessary filtration of fission products.
{continued)
* PBAPS UNIT 2                          8 3.3-169                              Revision No.* I
 
Secondary Containment Isolation Instrumentation B 3.3.6.2
* BASES (continued}
APPLICABLE        The isolation signals generated by the secondary containment SAFETY ANALYSES,  isolation instrumentation are implicitly assumed in the LCO, and          safety analyses of References 1 and. 2 to initiate closure APPLICABILITY      of valves and start the SGT System. to limit offsite doses.
Refer to LCO 3.6.4.2, RSecondary Containment Isolation Valves_ (SCIVs), and LCO 3.6.4.3, "Standby Gas Treatment 11 (SGT) System, Applicable Safety Analyses Bases for more 0
detail of the safety analyses.
The secondary containment isolation instrumentation satisfies Criterion 3 of the NRC Policy Statement. Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.
The OPERABILITY of the secondary containment isolation instrumentation is dependent on the OPERABILITY of the individual instrumentation channel Functions. Each Function must have the required number of OPERABLE channels wfth their setpoints set withtn the specified Allowable Values, as shown in Table 3.3.6.2-1. The actual setpoint is calibrated consistent with applicab]e setpoint methodology assumptions. A channel is inoperable if its actual trip
__sett_ing"_ ~ ~ not_ wi_!~i n !ts" !~~~i re9 __A~o!a~~-e -~~l ue. _______ _
Allowable Values are specified for each Function specified 1.n the Table. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setting less conservative than the trip setpoint, but within its Allowable Value, is acceptable.
Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g .. , reactor vessel water level), and when the measured output value of the process par.ameter exceeds the setpoi nt, the associated device (e.g., trip unit) changes state. The analytic or design limits are derived from the limtting values of the process parameters obtained from the safety analys.is or other appropriate documents. The Allowable Values are derived from the analytic or design limits, corrected for calibration, process, and instrument errors. The trip setpoints are then detennined from .analytical or design limits, corrected for calibration, process, and instrument
* PBAPS UNIT 2                              B 3.3-170 (continued)
Rev 1s i on No
* I
 
Secondary Containment Isolation Instrumentation B 3~3.6.2
  - BASES APPLICABLE            errors,. as we Tl as, instrument drift. In selected cases, SAFETY .ANALYSES,      the. Allowable Values and trip setpoints are determined by LCO, and              engineering jUdgement or historically accepted practice APPLICABI LITV        relative to the intended function of the channel. The (continued)          trip setpoints determined in this manner provide adequate protection by assuring instrument and process uncertainti.es expected for the environments during the operating time of the associated' channels are accounte~ for.
In general, the. individual Functions are ,required to be OPERABLE in the MODES or other spectfied conditions when SCIVs and the SST System are required.
                        - The specifk Applicable Safety Analyses, LCOf and Applicability discussions are listed below on a Function by Function basis.
L Reactor Vessel Water Level - Low {Level 3)
Low reactor pressure vessel (RPV) water level indkates that the capability to cool the fuel may 'be threatened. Should RPV water level decrease too far, fuel damage could result.
An isol'ation of the secondary containment and actuation of
                - - *- ~- th-e-sGT SJ*stenr a'Fe 1n1-ttatect111--orderttr7ni'nlm1-ze~hei-- - -_____, ---
potent1 a1 of an offsite. dose release. The Reactor Vessel Water Leve 1 - Low ( Leve 1 .3) Function is one of the Functions assumed to be OPERABLE and capable of providing isolation and initiation signals. The isolation and initiation systems on Reactor Vessel Water Level - Low (level 3) support actions to ensure that any offsite releases are within the limits calculated in the safety analysis.
Reactor Vessel Water Level - Low (Level 3) signals are initiated from level transmitters that sens*e the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual wate.r level (variable leg) in the vessel. Four channels of Reactor Vessel .Water Level - Low (Level 3} Function are available and are' required to be OPERABLE in MODES I, 2, and 3 to ensure that no single instrument fail,ure can preclude the isolation function.
{continued)
PBAPS UNIT 2                              B  3.3-171                      Revision No. l
 
Secondary Containment Isolation Instrumentation B, 3.3.6.2
* BASES APPLICABLE SAFHY ANALYSES,
: 1. Reactor Vessel Water Level-Low (Level 32  (continued)
LCD, and        The Reactor Vessel Water Level -Low (Level 3) Allowable APPLICABILITY  Value was chosen to be the same as "the RPS Level 3 scram Allowable Value (LCO 3.3,1.1), since isolation of these valves and SGT System start are not critical to orderly plant shutdown.
The Reactor Vessel Water Level-Low (Level 3) Function is required to be OPERABLE in MODES 1, 2, and 3 Where considerable energy exists in the Reactor Coolant System (RCS); thus, there is a probability of pipe breaks resulting in significant releases Of radioactive steam and ~as. In MODES 4 and 5, the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES; thus, this function is not required.
: 2. Drywel l Pressure:-Hi gh
* High drywell pressu~e can indicate a break in the reactor coolant pre.ssure boundary {RCPB). An isolation of the secondary containment and actuation of tne SGT System are-initiated in order to minimize the potential of an offsite dos release. The isolation on high dr,YWell press*ure supports actions to ensure that any offsite releases are within the limits ca*lculated in the safety analysis. The Drywell Pressure-High Function associated with isolation is not assumed in any UFSAR accident or transient ana7yses but will provide an isolation and initiation signal. It i.s retained for the overall redundancy a~d diversity of the secondary containment isolation instrumentation as required by the NRC approved licensing basis .
* PBAPS UN IT 2                    B 3.3-172                  Revision No. 145
 
Secondary Containment Isolation Instrumentation B 3.3.6.2
* BASES APPLICABLE SAFETY ANALYSES,
: 2. Ptvwell Pressure-Htqh (continued)
LCO, and        High drywell pressure signals are initiated from pressure APPL~CABILITY    transmitters that sense the pressure in the drywell. Four channels of Drywe 11 Pressure -- High Functions are avail ab le and are required to be OPERABLE to ensure that no single tnstrument failure can preclude perfonnance of the isolation function.
* The Allowable Value was chosen to be the same as the ECCS Drywall Pressure-High Function Allowable Value (LCO 3.3.5.1) since this is indicative of a loss of coolant accident (LOCA).
The Drywall Pressure-High Function is required to be OPERABLE in MODES l, 2, and 3 Where considerable energy exists in the RCS; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas. This Function is not required in MODES 4 and 5 because the probability and consequences of these events a:re low due to the RCS pressure and t~perature 1 imi.tati ons of these MODES.
3.,._4,, * -Reactor* BuUdi.rrq Ventftatton-a11d *'.Refu:e-1 inq-FJQor Ventilation Exhaust Radiation-High High secondary containment exhaust radiation is an indication of possible gross, failure of t'he fuel cladding.
The release may have origi,nated from the primary containment due to a break in the RCPB or during refueling due to a fuel handling accident. When Vent1l at ion Exhaust Radi at 1on .-High is detected, secondary containment isolation and actuation of the SGT System are initiated to limit the release of fission products as assumed in the UFSAR .safety analyses (Ref. 4).
The Ventilatton Exhaust Radiation-High signals are initiated from radtation detectors that are located on the ventilation exhaust piping coming from the reactor building and the refueling, floor zones, respectively. The. s.ignal from each detector is input to an individual monitor whose trip outputs are assigned to an isolation channel. Four
                                                                                <conti.nued}
PBAPS UNIT 2                          B 3.3-173                            Revision No. 1
 
Secondary Containment Isolation Instrumentation B 3.3.6.2
* BASES APP LI CABLE SAFETY ANALYSES,
: 3. 4,    Reactor Building Ventilation a  Q Refueling Floor Venti 1ati on Exhaust Radiation-Hi oh Ccontinued)
LCO, and APPLICABILITY    ch.annel s of Reactor BuiJ ding Ventilation Exhaust Radiation-High Function and four channels of Refueling Floor Ventilation Exhaust Radiation-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Values are chosen to promptly detect gross failure of the fuel cladding.
The Reactor Building Ventilation and Refueling Floor Ventilation Exhaust Radiation-High Functions are required to be OPERA BLE i n MOD ES 1 , 2 ,. a nd 3 whe re con s i de r ab 1e ene~gy exists; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas. In MODES 4 and 5, the probability and consequences of these events ere low due to the RCS pressure and temperature limitations of these MODES; thus, these Functions ar~ not -
required. In addition, the Functions are also required to be OPERABLE during movement of RECENTLY IRRADIATED FUEL assemblies in the secondary containment, beG~_L!Se tti_e ccpabi1ity of aetectirig raaiation relea-ses due to fuel failnres (d.ue to fuel uncovery or dropped fuel assemblies) must be provided to ensure that offsite dose limits are not exceeded.
ACTIONS          A  Note has been provided to modify tne ACTIONS related to secondary containment isolation instrumentation channels.
Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition.
Section 1.3 also specifies that Required Actions of the Condition continue* to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions foT inoperable secondary containment isolation instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entr-y for each inoperable secondary containment isolation instrumentation channel .
* PBAPS  UNIT 2                      B 3.3-174                        R:e v i s i on No . 14 5
 
Secondary Containment Iso1ation Instrumentation B 3.3.6.2
* BASES ACTIONS (continued)
AJ.
Because of the diversity of sensors av'a11ab1e to provide isolation signals and the redundancy of the isolatfon design, an allowabl~ out of service time of 12 hours for Functions 1 and 2, and 24 hours for Functions other than Functions 1 and 2, has been shown to be acceptable (Refs. 5 and 6) to permit restoration of any 'inoperable channel to OPERABLE status.. This out of service time is onl.y acceptable provided the associated Function is still maintaining i sol at ion capability (r*efer to Required Action B.1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A. I. Placi,ng the inoperable channel in trip would conservatively compensate for the inoperabil ity, restore capabi 11ty to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g.j as in the case wb~re placing the inoperable channel in trip would result in an isolation), Condition C must be entered and its
* Require~ Actions taken .
Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, 1noperable, untripped channels within the same function result in a complete loss of isolation capability for the associated penetration flow path(s) or a complete loss of automatic initiation capat>ility for the SGT System. A Function is considered to be maintaining secondary containment isolation capability when sufficient channels are OPERABLE or in trip, such that both trip systems will generate a trip signal from the given Function on a valid signal. This ensures that at least one of the two SCIVs in the associated penetration flow path and at 1east one. SGl subsystem can be hiitiated on an isolation signal from the given Function. For Functions 1, 2 ,. 3, and 4., this would require both trip systems to have one channel OPERABLE. or in trip.
                                                                      <continued)
* . PBAPS UN IT 2                  B 3.3-175                      Revision No. 1
 
Secondary Containment Isolation Instrumentation B 3.3.6.2
* BASES ACTIONS      Ll {continued)
The Cotapletion Time is intended to allow the .operator time to evaluate and repair any discovered inoperabil it1es. The I hour Completion Time is acceptable because it mi.nimizes risk while allowing time for restoration or tripping of channels.
C.1.1. C.1.2, C,2,1. and C.2.2 If any Required Action and associated Completion Time of Condition A or B *are not met, the ability to isolate the secondary containment and start the SGT System cannot be ensured. Therefore, further actions must be performed to ensure the ab11 ity to mainta.in the secondary containment function. Isolating the associated secondary contai.nment penetration flow path(s) and starting the associated SGT subsystem (Required Actions C. l. l and .C. 2. I) performs the intended function of the instrumentation and allows operation to continue .
* Alternately, declaring the associated SCIVs or SGT.
subsy.stem(s} inoperable (Required Actions C.l.2 and C.2.2)
              ~*is- al-so--a.cceptabl e -since* the -Required-Act-ions -of-t-he-.,
respective LCOs (LCO 3.6.4.2 and LCO 3.6.4.3) provide appropriate actions for the inoperable components.
One hour is sufficient for plant operations personnel to est~blish requir~d plant conditions or to declare the associated components inoperable with out unnecessarily challenging plant systems.
SURVEILLANCE  As noted at the beginning of the SRs, the SRs for each REQUIREMENTS  Secondary Containment Isolation instrumentation .Function are located in the SRs column of Table 3,3.6.2-1.
                                                                            <continued)
* PBAPS UNIT 2                        B 3.3-176                          Revision No. I
 
Secondary Containment Isolation Instrumentation B 3.3.6 .. 2
* BASES SURVEl LLANCE REQUIREMENTS The Surveillances are modified by a Note to indicate that when a channel is placed in arr inoperable status solely for (continued)  performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains secondary containment isolatton capability. Upon completion of the Surveillance, or expirat1on of the 6 hour allowance, the chan,ne7 must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.
Th i s Note i s !)a s ed o.n t he r e 11 a bi 1it y a na 1y s i s ( Refs . 5 and .6) assumption that of the average time required to perform channel survei J 1ance. That analysis demonstrated the 6 hour testing allowance does not significant1y reduce the probability that the SCIVs will isolate the associated penetration flow paths and that the SGT System will initiate when necessary.
SR 3,3,6,2.1 Performance of the CHANNEL CHECK ensures t~at-a gross
* failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the. parameter indicated on one channel to a similar parameter on other channels. It is
                -hased -on the -a-ss umpt fon lnat *1 nslrumefft --cnaiihels___mo-n itorl ng the same parameter should read approximateJy the same value, Signiflcant deviations between th.e instrument ch.annels could be an indication of excessive instrument drift in one
                ,of the cha nne 1s or something even mo re serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
Agreement criteria are determined by the pfant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.
The Survei.llance Frequency is controlled under the Surveillance Freque,ncy Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the cti~plays associated with c.hanne1s required by the LCO .
* PBAPS UNIT 2                        B 3.3-177                                Revishln No. 86
 
Secondary Containment Isolation Instrumentation B 3.3.6.2
* BASES SURVEI lLANeE REQUIREMENTS SR 3.3.6.2,2
( continued) A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the inter:ided function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR 3.3,6.2.3 and SR 3.3.6.2.4T A CHANNEL CALIBRATION is a c.omplete che.ck of the i rlstrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations, consistent with the current plant specific setpoint methodology .
* The Surveillance Frequency is controlled under the Surveillance Frequency Control PrDgram, SR .3 . 3. 6, 2*5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the 0 PERA BI LIT Y of t he re qui red i s ol at i on l ogi c fo r a s pe cif i c channel. The system functional testing performed on SCI Vs and the SGT System in LCO 3.6.4.2 and ~co 3.6.4.3, respectively, overlaps this Surveillance to prov~de complete testing of the assumed safety function.
The Surveillance Frequency is controlled under the Survei 11 ance Freque,ncy Control Program.
(continued)
* PBAPS LJN IT 2                      B 3.3-178                            Revision No'. 86
 
Secondary Containment Isolation Instrumentation B 3.3.6.2
* BASES  (continued)
REFERENCES        1. UFSAR, Section 14.6.
: 2. UFSAR, Chapter 14.
: 3. UFSAR, Section 14.6.5.
: 4. UFSAR, Sections 14.6.3 and 14.6.4.
: 5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR lsolation Actuation Instrumentation,"
July 1990.
: 6. NEDC-30851P-A Supplement 2, Technical Specifications 0
Improvement Analysis for BWR Isolation Instrumentation Convnon to RPS and ECCS Instrumentation," March 1989 .
* PBAPS UNIT 2                      B 3.3-179                    Revision No'" 1
 
MCREV System Instrumentation B 3.3.7.1
* B 3.3  INSTRUMENTATION B 3.3~7.1 Main Control Room Emergency Ventilation (MCREV) System Instrumentation BASES BACKGROUND          The MC REV System is *designed to provide a radio 1 og i ca11 y controlled env1ronment to ensure the habitability of,the control room for the safety of control room operators under all plant canditions. Two independent MCREV subsystems are each capable of fulfilHng the stated safety function. The instrumentation and controls for the MCREV System automatically initiate action to pressurize th~ main control room (MCR} to minimize the consequences of radioactive material in the control room environment.
In the event of a Control Room Air Intake Radiation-High signal, the MCREV System is automatkally started in the pressurization mode. The outside air from the normal ventilation intake is then passed through one of the charcoal filter subsystems. Sufficient outside a1r is drawn in through the nonnal ventilation intake to maintain the MCR
* slightly pressurized with respect to the turbine building .
The. MCREV System instrLimentation has two trip systems with
                  - -two tontr-oT*RooiJf AH*-1ntake Ra:d1-atHm~-Hlgtrt:tramrels--1n~each- - " - --
trip system. The outputs of the Control Room Air .Intake Radiation-High channels are arranged in two trip ~ystems, which use a one-out-of-two logic. The tripping of both trip systems will initiate both MCREV subsystems. The channels include electronic equipment (e.g., t~ip units) that compares measured input s:ignal s wi.th pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, wh.ich then outputs a MCREV System tnitiation signal to the initi'ation logic.
APPLICABLE .        The ability of the MCREV _System to maintain the ha.bitabil ity SAFETY ANALYSES,    of the MCR is explicitly assumed for certain accidents as LCO, and            discussed in the UFSAR safety analyses (Refs. 1, 2, and 3).
APPLlCAB-ILITY      MCREV System operation ensures that the radiation exposure of control room personnel, through the duration of any one of the postulated. accidents, does not exceed acceptable limits.
(continued)
* PBAPS UNJT 2                          8 3.. 3-180                      Revision No. 1
 
MCREV System Instrumeotation B 3.3.7.l
* BASES APPLICABLE        MCREV System instrumentation satisfies Criterion 3 of the SAFETY ANALYSES,  NRC Policy Statement.
LCO, and APPUCABI LITY      The OPERABILITY of the MCREV System instrumentation is (continued)      dependent upon the OPERABILITY of the Control Room Air Intake Radiation --High instrumentation channel Function ..
The Function must have a requi.red number of OPERABLE channels, with their setpoints within the specified Allowable Values, where appropriate. A channel is inoperable if its actual trip setting is not Within its requ,ired AllowabJe Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Allowable Values are specified for the HGREV System Control Room Air Intake Radiation-High Function. Trip setpoints are specified in the setpoint calculations. The trip setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setting less conservative than the trip setpoint, but within its Allowable Value, is acceptablle.. Trip setpoints are those predetennined values of output at which an action should
* take place. The setpoints are compared to the actual process parameter (e.g., control room air intake radiation),
__ and__~en t~e "_measu_re<J __out_p_ut ya l ue of the process parameter exceedsthe se:tpoint, the ass-ociated dEfvice- cliang-e"s- state.
The analytic. limits are derived from the limiting values of the process parameters obtained from the safety analysi*s.
The Allowable. Values are derived from the anal,ytic l:imits, corrected for calibration, process, and instrument errors.
The trip setpoin.ts are determined from analytical or design limits, corrected for calibration, process, and instrument errors, as well as, instrument drift. The trip setpoints derived in this manner provide adequate protection by ensuring instrument and process uncertainties expected for the environments during the operating time of the associated channels are accounted for.
The control room air intake radiation monitors measure radiation levels in the fresh air supply plenum. A Mgh radiation level may pose a threat to MCR personnel; thus,,
automatically initiating the MCREV System.
                                                                                <continued}
PBAPS UNIT 2                          B 3.3-181                            Rev i s ion No . 1
 
MC REV Sys ten, Inst rumen tat ion B 3.3.7.1
* BASES APPLICABLE SAFETY ANALYSES, LCO, and The Control Room Air Intake Radiation-High Function consists of four independent monitors, Two channels of Control Room Air Inta.ke Radiation-High per trip system are APP LI CAB! LITY  available and are required to be OPERABLE to en'sure that no (continued)    single instrumen~ failure can preclude MCREV System initiation. The Allowable Value was selected to ensure protection of the control room personnel.
The Control Room Air Intake Radiation-High Function is required to be OPERABLE in MODfS 1, 2-, and 3 and during CORE ALTERATIONS, and movement of irradiated fuel assernb'l i es in the secondary containment, to ensure that control room personn.el are pr0tected. tluri ng a LOCA, or fucel handl i.ng event. During MODES 4 and 5, when these specified conditions are not in progress (e.g., CORE ALTERATFONS), the probability of a LOCA or fuel damage is low; thus, the Function is not required.
ACTIONS          A Note has been provided to modify the ACTIONS related to MC REV System instrumentation channels. Sect1 on 1. 3, Completion Times, specifies that once a Condition has been
* entered, subsequent divisions, subsystems, components, or variables expressed in*the Condition, discovered to be
                  ~-inoperable .or not within- im-it-s,- wHl not resuH in s-eparate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additi0nal failure, with Completion Times based on initial entry into the Condi-ti on. However, the Re qui red Actions for inoperab.le MCREV System instrume-ntation cha-nne1s provide appropriate compensatory measures. for separate i noperabr e channels. As such, a Note has b-een pr-ovit;led that allows separate Condition entry for each inoperable MCREV System instrumentation channel.
A, l_ and A.2 Because of the redundancy of sensors available to provide initiation signals and the redundancy of the MCREV System destgn, an allowable out of service time of 6 hours has been shown to be acceptable (Ref. 4), to permit restoration of any i nopera b1 e ch 9 nne l to OPERAS LE stat us. However, this out of service time is only acceptable pro.vided the Control Room Air Intake Radiation-High Functi.ori is still maintaining MCREV System initiation capability. The Fl.'.lnction is considered to be maintaining MCREV System
* PBAPS UN IT 2                          B 3.3-182                        Revision N-o. 145 d
 
MCREV System Instrumentation B 3.3.7.I
* BASES ACTIONS      A.I and A.2      (continued) initiation capability when sufficient channels are OPERABLE or in trip such that the two trip systems Will generate an initiation sfgnal from the gfven Function on a valid signal.
For the Control Room Air Intake Radiation-High Function,
              'this would require the two trtp systems to have one channel per trip systam OPERABLE or in. trip. In this situation (loss of MCREV .System initiation capability), the 6 hour allowance of Required Action A.2 is not appropriate. If the Function iS not maintaining MCREV System initiation capability, the MCREV System must be declared inoperable within I hour of discovery of the loss of MCREV System initiation capability 1n both trip systems.
The I hour Completion Time (A.I) ts acceptable because it 11in,i.mizes risk. while allowing time for restoring or tripping of channel s.
If the inoperable channel cannot be restored to OPERABLE status witMn the allowable out of service tirne, the channel must be placed in the tripped condition per Required
* Action A.2. Plactng the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to acc~mmodate a_ sin_gle failure, and allow operation to continue. Alternately, -TfTt 1s-rl0faeslrecl to-place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation}, Condition B must be entered and its Required Actton taiken.
B.l and B.2 With any Requi.red Action and associated Completion Time not met,' the associated HCREV subsystem(s) must be placed in operation per Required Action B.1 to ensure that control room personnel will be protected in the event of a Design Basis Accident. The method used to place the MCREV          -
subsystem(s) in operation must provide for automatic-ally re-initiating, the subsystem(s) upon restoration of power following a loss of power to the HCREV subsystem(s).
Alternately, if it is not desired to start the subsystem(s),
the HCREV subsystem(s) associated with inoperable, untripped
                                                                    <continued}
* PBAPS UNIT 2                    B 3.3-183                    Revision No,. 1
 
MCREV System Instrumentation B 3.3.7.1
* BASES ACTIONS            8,1 and B,2 fcontinued) channels must be declared inoperable within 1 hour. Since each trip system can affect both MCREV subsystems, Required Actions B.1 and B.2 can be pe.rformed independently on each 1-fCREV subsystem. That is, one MCRtV subsystem can be pTacied in operation (Required Action B.1) while the other MGREV subsystem can be declared inoperable (Required Acti.On B.2).
The 1 _hour Completion Time is intended to allow the operator time to place the MCREV subsystem(~) in operation. The 1 hour Completion Time- is acceptable because 1t minimizes risk while allowing time for placing the asso,ciated MCREV subsystem(s) in operation, or for entering the ~pplfcable Conditions and Required Actions for the in0perable MCREV subsystern(s),
SU RV !:I LLAN GE  The Surveillances are modified by a Note to indicate that REQUIREMENTS      when a chan~el is placed in an inoperable status solely for performance of required Surveillances, entry into associated tonditions and Required Actions may be delayed for up to
* 6 hours, provided the associqted Function maintains MGREV System i niti ati on capabi.l ity. - Upon completion of the Surveillance, or expiration of the 6 hour allowance, the.
                    -cha-nne*f musT-be~re-hrnect to 6F>ERABLCsFatus or*-fhe* --- --- --
applicable Condition entered and Required Actions taken.
This Note is based on the reliability analysis (Ref. 4) assumption of the average time requtred to perform channel suJ'Vei 11 anc.e.. That analysis demonstrated tha.t the 6 hour te~ting allowance does not significantly reduce the probabi.lity that the MCREV System Wi17 initiate when necessary.
SR    3.3.7,1.1 Performance of t~e CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter 1ndicated on one channel to a similar parameter on other channels. It is based 0n ttie assumption that instrument channels monftoring th~ same parameter should read approximately the same value.
Significant.deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect
* P'BAPS UNIT 2                          B 3.3-184                      Revision No. 86
 
                                                      - MCREV System Instrumentation B 3. 3 .? .1
* BASES SUR\JEI LLANCE  SR 3.3.7.1.1      (continued)
REQUIREMENTS gross channel failure; thus, it is key to verifying the instrumentation cont1nlles to operate properly between each CHANNEL CALIBRATION.
Agreement criteria are determined by the plant staff, based on a combinatton of the channel instrument uncertainties, 1ntlud1ng ind1cat1on and readabil1ty. If a channel is outside the criter1a, it may be an 1ndication that the instrument has drifted outside its limit.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operatio~al use of the displays associated with channels requfred by the LCO.
SR 3.3.7,1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. Any setpoint adjustment shall be
_c_onsis_teQt __lvjto the_ as_sumptions of the current pl~nt specif1 c setpo1 r:it methodology.          *- - -- -- - -
The Surveillance Frequency is control~ed under the Surveillance Frequency Control Program.
SR 3,3.7.1.3 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channe1 responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION h:aves the channel adjusted to account for instrument drifts between successive calibrations, consistent with the assumptions of the plant specific setpoint methodology.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .
* PBAPS UN IT 2                        B 3.3-185                    Revision No. 86
 
MCREV System Instrumentation B 3.3.7.1
* BASES SUR\JE IL LANCE SR  3.3,7.1.4 REQUIREMENTS (continued)  The LOGIC SYSTEM FUNCTIONAL TES1 demonstrates the OPERABILITY of the req~red initiation logic for a specific channel. The system functional testing performed in LCO 3.7.4, "Main Control Room E:mergehcy Ventilation (MGREV)
System," overlaps this Surveillance to provide complete testing of the assumed safety function.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
REFERENCES      1. UFSAR, Section 10.13.
: 2. UFSAR, Section 12.3.4.
: 3. UFSAR, Section 14.9.1.5.
: 4. GE NE - 77 O- O6 - 1 , Ba se s f o r Ch a nge s t o Su r v e i ll a nc e Te s t 11 Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Speci fi cations,                    11 February 1991 .
* PBAPS UN IT 2                          B 3.3-186                              Revisiori No. 86
 
LOP Instrumentation B 3.3.8.1
* B 3.3 INSTRUMENTATION B 3 .3.8. l Loss of .Power (LOP) Instrumentation BASES BACKGROUND        Successful operation of the required safety functtons of the Emergency Core. Cooling Systems {ECCS) is dependent upon the.
avai,labiHty of adequate power for energizing various C0111Ponents such is pump motots, motor operated valves, and the associated control components. The LOP instrumentation monitors the 4 kV emergency bUses voltage. Offsite. power is
* the preferred source of power for the 4 kV emergency buses ..
If_the LOP instrumentation detects that voltage levels are too low, the buses are disconnected from the offsite power sources- and connected to the onsite diesel generator (DG) power sources.
Each Unit 2 4 kV emergency bus has its awn independent LOP instru~ntation and associated trip logic. The voltage for each bus is 1DOnitored at five levels, which can be considered as two different undervoltage Functions: one level of loss of voltage and four levels of degraded
* voltage. The Functions cause various bus transfers and disconnects. The degraded voltage Function is 1DOnitored by four undervoltage relays per source and the loss of voltage
                      -Functton-*i s--moni torel:t-by *one- undervrrltage~-re-'1 ay--for- -e-actr ---- - -- -
emergency bus. The degraded voltage outputs and the loss of voltage outputs are arranged in a one-out-of-one trip logic configu,ration. Each channel consists of four protective relays that compare offs1te source voltages with pre-established setpoints. When the sensed voltage is below the setpo.int for a degraded voltage channel, the preferred offsite source breaker to the 4 fcV emergency bus i's tripped and autotransfer to the alternate offsite source is ini,tiated. If the a.lternate source does not provide adequate voltage to the bus as sensed by its degraded grid l                    relays, a: diesel generator start signal is initiated.*
A description of the Untt 3 LOI' instrumentation is provided in the Bases for Unit 3 LCO 3.3.8.1.
(continued)
* PBAPS UNIT 2                            B 3.3-187                              Revision No. 5
 
LOP Instrumentation B 3.3.8.1
* BASES    (continued)
APP LI CA.BLE        The LOP instrumentation is required for Engineered Safety SAFETY ANALYSES,      Features to function in any accident with a loss of offsite LCO, and              power. The required channels of LOP instrumentation ensure APPLICABILITY        that the tees ~nd other assumed systems powered from the DGs, provide plant protection in t~e event of any of the Reference 1 (UFSAR) analyzed accidents in which a loss of offs i te power is assumed. The first level is loss of voltage. This loss of voltage level detects a.nd disconnects the Class lE buses from the offsite power source upon a total loss of voltage. Th.e second level of undervoltage protectton is provided by the four 1evels of degraded grid voltage relays which are set to detect a sustained low voltage condition. These degraded grid re1ays disconnect the Class lE buses from the offsite power source if the degraded voltage cond1tien exists for a time interval which could prevent the Class lE equipment from achieving its safety function. The degraded grid relays also prevent the Class lE equipment from sustaining damage from prolonged operation at reduced voltage, The combination of the loss of voltage relaying and the degraded grid relaying provides protection to the Class lE dtstribution system for all credible co~ditions of voltage collapse or ~ustained voltage degradation. The initiation of the  Gs on loss of offsite power, and subsequent initiation of the ECCS, ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Accident analyses credit the loading of the DG based on the loss of offsite power during a loss of coolant accident.
The diesel starting and loadirg times have been included in the delay time associated with each s~fety system component requiril1'9 DG supplied power following a loss of offsite power.
The LOP instrumentation satisfies Criterion 3 of the NRC Policy Statement.
The OPERABILITY of the LOP instrumentation is dependent upon the OPERABILITY of the individual instrumentation relay
* channel Functions specified in Table 3.3.8.1-1. Each Function must have a required number of OPERABLE channels per 4 kV emergency bus, with their setp0ints within the specified Allowable Values except the bus undervoltage relay which does not have an Allowable Value. A degraded voltage channel is inoperable if its actual trip setpoi~t is not within its required Allowable Value. Setpoints are calibrated consistent with the Improved Instrument Setpoint Control Program (IISCP) methodology assumptions .
* PBAPS UN IT 2                            B 3. 3-188                  Revision No. 88
 
LOP Instrumentation B 3.3.8.1
* BASES APPLICABLE SAFETY ANALYSES, The. loss of voltage channel is inoperable if it will not start the diesel on a loss of power to a 4 kV emergency bus.
L.CO, and APPUCABI LiiY      The Allowable Values a~e specffied for each applicable (continued)      Function in the Table 3.3.8.1-1. The nominal setpoints are selected to ensure that the setpoi nts do not ex.ceed tt:ie.
Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint within the Allowable Value, is acc:e.ptable. Trip setpoints are those predetermined values of output at Which an action should take pl ace. The setpoints are comp~red to the actual process parameter (e.g., voltage), and when the measured output value of the process parameter exceed~ the setpoint, the protective relay output changes state. The Allowable Values were set equal to the limiting values determined by the voltag.e reg.u1atio.n calculation. The setpoints ~ere corrected using IISCP method a T0gy to account for re 1ay drift, relay a c:curacy, potential tra.nsformer accuracy, measuring a*nd test equipment accuracy mar.gin, and includes a calibration leave alone zone. IISCP methodology utilizes the square root of the sum of the squares to combine random non-direct1onal accuracy values. IISCP then includes relay drift, calibration leave alone zo.nes, and margins. The setpoint assumes a nominal 35/1 potential transformer ratio .
The specific Applicable Safety Analyses, LCO, and
_ .bR.R.li.e11.bj_l iJ;_y J11stussi_ons _for Unit 2 LOP_ instrumentation  q__f_:g ____ _
liste.d below on a Func.tio_n by function basis.
In addition, since some equipment required by Unit 2 is powered fra,m Unit 3 sources, the Unit 3 LOP' i nstrumentati o,r:1 supporting the required sources must also be OPERABLE. The OPERABILITY requirements for the Unit 3 LOP instrumentation is the same a.s describ.ed in this section, except Function 4 (4 kV Emergency B,us Undervoltage, D'egraded Voltage LOCA) is not required to be OPERABLE, s i nee this Fun ct j on 'is related to a LOCA on Unit 3 only. The Unit 3 instrumentation fs listed in Uhit 3 Table 3.3.8.1-1.
1, 4 kV Emergency Bus UndervoJtage Closs of Voltage)
When both offsite sources are last1 a loss of voltage condition on a 4 kV emergency bus indicates that the respective emergency bus is unable to supply sufficient power for proper operation of the applicable equipment.
Therefore, the power supply to the bus is transferred from offsite power to DG power. This ensures that adequate power wtll be available to the requ1red equipment .
* PBAPS UN IT 2                                B 3.3-189                        Revision No. 88
 
LOP Instrumentation B 3 .. 3.8.1
* BASES
  -------~-------~--~------------------
APPLICABLE        1. 4 kV Emergency Bus Undervoltage Closs of Voltage)
SAFETY ANALYSIS,    cconti nu,ect 2 LG0, and APPLICABILITY    The single channel of 4 kV Emergency Bus Undervoltage (Loss of Voltage) Function per associated emergency bus is only required to be OPERABLE when the associated 0G and offsite circuit are required to be OPERABLE. This ensures no single instrument failure can preclude the start of three of four DGs. ( One channel inputs to each of the four DGs.) Refer to LC 0 3 . 8 . 1 ,. "AC Sources - Ope r cl ti ng , " and 3 . 8. 2 , "AC Sources-Shutdown," for Applicability Bases for the DGs.
2*. 3** 4*. 5. 4kV Emergency Bus unctervoltage (Degraded
                  - Voltage)
A degraded voltage condition on a 4 kV emergency bus indicates that, while offsite power may not be completely lost to the respective emergency bus, available power may be insufficient for starting large ECCS motors without risking damage to the motors that could disable the ECCS function.
T~erefore, power to the bus is transferred from offsite power to onsite DG power when there is insufficient offsite power to the bus. This transfer will occur only if the
* voltage of the preferred and alternate power sources drop below the Degraded Voltage Function Allowable Values (degraded voltage with a time delay) and the source breakers
                  --trip-whieh-causes-the-bus unde-r-voltage relay to i-nitiate-the DG. This ensures that adequate power Will be available to the required equipment.
Four Functions are provided to monitor degraded voltage at four different levels. These Functions are the Degraded Voltage Non- L0CA, Degraded Voltage L0CA, Degraded Voltage High Setting, and Degraded Voltage Low Setting. These relays monitor the following voltage levels with the following time delays: the Function 2 relay, 2286 - 2706 volts in approximat~ly 2 seconds when source voltage is reduced a.bruptly to zero volts (inverse time delay); the Function 3 relay. 3409 - 3829 volts in approximately 30 seconds when source voltage is reduced abruptly to 2940 volts (inverse time delay); the Function 4 relay, 3766 -
3836 volts in approximately 10 seconds; and the Function 5 relay, 4116 - 4186 volts tn approximately 60 seconds. The Function 2 and 3 relays are inverse time delay relays.
These relays operate along a repeatable characteristic curve. With relay operation being inverse with time, for
* PBAPS UN IT 2                            B 3.3-190,                            Revision No. 88
 
LOP Instrumentation B 3.3.8.I
* BASES APPLICABLE          2. , 3, , 4, , 5. 4 kV Emergency Bus UndervoJ taae <Degraded SAFITY ANALYSES, Voltage) (continued)
LCO, and APPLICABILITY        an abrupt reduction in voltage the relay operatfngtime will be short; conversely, for a slight reduction in voltage., the ope.rating time delay will be long.
The Degraded Voltage LOCA, Funct i,on preserves the assumpt 1ons
* of the LOCA analysis and the combined Functions of the other l                      relays preserves the. assumptions of the accident sequence analysis in the UFSAR. The Degraded Voltage Non-lOCA Function provides assurance that equipment powered from the 4kV emergency buses ts not damaged by degraded voltage that might occur under other than LOCA conditions. This degraded grid non-LOCA relay has an associated 60 second timer. This timer allows fo.r offsite source transfonner load tap change,r ope.ration. Degraded voltage conditions can be mitigated by-tap changer operations and othe.r manual acticms. The 60 second timer provides the time for these actions to take place.
* The degraded grid voltage Allowable Values are low enough to
* prevent inadvertent power supply transfer, but high enough to ensure that sufficient power is available to the required equipment~ The Time Delay Allowable Values are long enough
                    * - --to-1>r0vfde -t 1me for -the -offs 1te--power -supp~y-to-- recover-to- --
normal.voltages, but short enough to-ensure that sufficient power is availa:ble to the required equipment.
Two channels (one channel per source) of 4 kV Emergency Bus Deg,raded Voltage (Func'tions 2, 3, 4, and 5) per associated bus are required to be OPERABLE when the associated DG and offsite circuit are required to be OPERABLE. This ensures no, single instrument failure can preclude the start of three of four DGs ( each 1ogi c inputs to each of the four DGs) .. Refer to LCO 3.8.1 and LCO l.8.2 for Applicability Bases for the DGs.                                    --
ACTIONS              A  Note has been provided (Note 1) to modify the ACTIONS telated to LOP instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, ,components, or variables expressed in the Cond.ition, di.scovered to be inoperable or not Within limits, will not result in separate entry into the Cond,ition. Section 1.3 also spedfies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial
* PBAPS UNIT 2                              B 3.3-191 (continued)
Revision No~ 5
 
LOP Instrumentation B 3.3.8.1
* BASES ACTIONS            entry into the Condition. However, the Required Actions for (continued)  inoperable LOP instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable LOP instrumentation channel. ,
Pursuant to LCO 3.0.6, the AC Sources-Operating ACTIONS would not have to be entered even if the LOP instrumentation inoperability resulted in an inoperable offsite circuit.
Therefore, the Required Action of Condition A is modified by a Note to indicate that when performance of a Requi.red Action results in the inoperabil ity of an offsite circuit, Actions for LCO 3.8.1, "AC Sources -Ope.rating," must be innediately entered. A Unit 2 offsite circuit is considered to be inoperable if it is not supplying or not capable of supplying (due to loss of autotransfer capability) at least three Unit .2 4 kV emergency buses when the other offsite circuit i.s providing power or capable of supplying power to all four Unit 2 4 kV emergency buses. A Unit 2 offsite
* circuit is also considered to be inoperable if the Unit 2 4 kV einergency buses being powered or capable of being powered from the-two offsite circuits are all the same when
* at least-1me of the-two*circuits does not-provide*power or is not capable of supplying power to all four Unit 2 4 kV emergency buses. Inoperabil ity of a Unit 3 offsite circuit is the same as described for a Unit 2 offsite circuit,.
except that the. circuit path is to the Unit 3 4 kV emergency buses required to be OPERABLE by LCO 3.8.7, "Distribution Systems-Operating.* The Note allows Condition A to provide requtrements for the loss of a LOP instrumentation channel without regard to whether an offs1te circuit is rendered inoperable. LCO 3.8.1 provides appropriate restriction for an inoperable offsite circuit.
Required Action A.1 is app.l i cab1e when one 4 kV eme.rgency bus has one or two required Function 3 {Degraded Voltage High Setting) channels inoperable or when one 4 kV emergency bus has one or two required Function 5 (Degraded Voltage Non-LOCA) channels inoperable. In this Condition, the affected Function may not be capable of performing its intended function automat i ca1 l y for these, buses. However, the operators would still receive i,ndication 1n the control room of a degraded voltage condition on the unaffected buses and a manual transfer of the affected bus power supply to
* PBAPS UNIT 2                      B 3.3-192 (continued)
Revision No. 5
 
LOP Instrumentation B 3.3.8.1
* BASES ACTIONS      AJ. (continued) the altern.ate source could be made without damaging plant equipment. Therefore, Required Action A.I allows 14 days to restore the inoperable channel(s) to OPERABLE status or place the inoperable channel(s} in trip. Placing the inoperable channel, in trip would conservatively compensate for the i noperabil ity ,. restore des 1gn trip capabi 1 i ty to the LOP instrumentation, and a11 ow operation to continue.
Al,ternatively, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in D6 initiati,on), Condition D must be entered and its Required Action taken.
The 14 day Completion Time is intended to allow time to restore the thannel(s) to OPERABLE status. The Completion Time takes into consideration the diversity of the Degraded Voltage Functions, the capabilities of the remaining OPERABLE LOP Instrumentation Functions on the affected, 4 kV emergency bus and on the other 4 kV emergency buses (only one 4 kV emergency bus is affected by the inc;,perable channels),-the fact that the Degraded Voltage-High Setting
* and Degraded Voltage Non-LOCA Functions provide only a marginal increase in the protection provided by the voltage 110n1toring scheme, the low probability of the grid operating
              -1 n the**vo-1 tage -band protected-by -these -Funct--1 ans-,- --and--t-he ability of the operators to perform the Functions manually *
                .lL..l Pursuant to LCO 3. 0. 6, the AC Sources -- Operating ACTIONS would not have to be entered even if the LOP instrumentation inoperability resulted in an inoperable offsite circuit.
Therefore, the Required Action of Condition B is modified by a Note to indicate that when performance of a Requ,ired Action results in the inoperabil ity of an offsite circuit,._.,
Actions for LCO 3.8.1, RAC Sources-Operating, n must be
* tinmedfately entered. A Unit 2 offsite circuit is considered to be inoperable if it is not supplying or not capable of supplying (due to loss of autotransfer capability) at least three Unit 2 4 kV emergency buses when the other offsite circuit is providing power or capable of supplying power to all four Unit 2 4 kV emergency buses. A Unit 2 offsite circuit is also considered to be inoperable 1f the Unit 2 4 kV emergency buses being powered or capable of being powered from the two offs ite circuits are a11 the same when at least one of the two circuits does not prDvide power or
* PBAPS UNIT 2                      B 3.3-193 (continued)
Revision No. 5
 
LOP Instrumentation B 3.3.8.1
* BASES ACTIONS      Ll (continued) is not capable of supplying power to all four Unit 2 4 kV emergency buses. lnoperability of a Unit 3 offsite circuit is the. same as described for a Unit 2 offsite circuit, except that the circuit path is to the Unit 3 4 kV emergency buses required to be OPERABLE by LCO 3.8.7, nDistribution Systems - Operating ..
* This a11 ows Condition B to provide requirements for the loss of a LOP instrumentation channel without regard to whether an offsite circuit is rendered inoperable. LCO 3.8.l provides appropriate restriction for an inoperable offsite circutt.
Required Action B.1 is applicable when two 4 kV emergency buses have one required Function 3 (Degraded Voltage High Setting) channel inoperable, or when two 4 kV emergency buses have one required Function 5 (Degraded Voltage Non-LOCA) channel inoperable, or when one 4 kV emergency bus has one required Function 3 channel inoperable and a different 4 kV emergency bus has one required Function 5 channel inoperable. In this Condition, the affected Function may not be capable of performing its intended function automatically for these buses. However, the operators would still receive indication in the control room of a degraded voltage condition on the unaffected buses and a manual
              --transfer-of the-aff-ec-ted bus-powe.r supply "to the-alternate-source could be made without damaging plant equipment.
Therefore, Required Action B.l allows 24 hours to restore the i nope.rah1e channe1s to ,OPERABLE status or p1ace the inoperable channels in trip. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore design trip capability to the LOP instrumentation, and allow operation to continue.
Alternatively, if it is not desired to place the channe1 in trip (e.g., as in the case where placing the thannel in trip would result in DG initiation), Condition D must be entered and its Required Action taken.
The 24 hour Completion-Time is intended to allow time to restore the channel(s) to OPERABLE status. The Completion Time takes into consideration the diversity of the Degraded Voltage Functions, the capabilities of the remaining OP.ERABL&#xa3; LOP Irrstrumentation Functions on the affected 4 kV emergency buses and on the other 4 kV emergency buses (only two 4 kV emergency buses are affected by the inoperable channels) , the fact that the Degraded Vo.l tage High Setting and Degraded Voltage Non-LOCA Functions provide only a
* PBAPS UNIT 2                    B 3.3-194
                                                                      <continued)
Revision No. 5
 
LOP Instrumentation B 3.3.8.1
* BASES ACTIONS      Ll (continued) marginal increase in the protection provided by the voltage monitoring scheme. the low probability of the grid operating in the voltag.e band protected by these Fun~tions, arfrl the ability 0f the operators to perform the Function~ manually.
L_l Pursuant to LCO 3.0.6, the AC Sources-Operating ACTIONS wo*uld not have to be entere-0 even if the LOP Instrumentation i nope r a bi l it.y re s ult ed 1n .a n i nope r a b1e off s it e c i r c uit .
Therefore, the Required Action of Condition C is modified by a Note to indicate that when performance of the Required Action results in the inoperability of an offsite circuit, Act i on s fo r LC O 3 . 8 . 1 , " AC So ur t e s - 0 pe r at i ng , " mu st be immediately entered.            A Unit 2 off site circuit is considered to be inoperable if it is not supplying or not capable of supplying (due to loss of autotransfer capability) at least three Unit 2 4 kV emergency buse*s when the other offsite circuit is providing power or capable of supplying power t*o all four Unit 2 4 kV emergency buses. A Unit 2 offsite circuit is also considered to be inoperable if the Unit 2 4 kV emergency buses being powered or capable of _,bej ng _pQWer.e.d fr.om th.e. tw.o__ of_f;;_i t:Et _&#xa3;j_rcl)_i t.s 9:c~ a, 11 j:J:1~
same when at least one of the two circuits does not provide pow.er or is not capable of supplying power to all four Unit 2 4 kV emergency buses. Inoperabil ity of a Unit 3 offsite circuit is t~e same as described for a Unit 2 offsite circuit, except that the circuit path is to the Unit 3 4 kV emergency buses required to be OPERABLE by LCO 3.8.7, "Distribution Systems - Operating." The Note allows Condition C to provide requirements for the loss of a LOP instrumentation channel without regard to whether an offsite circuit is rendered inoperable. LCO 3.8.1 provides appropriate restriction for an inoperable offsite circuit.
Required Action C.l is applicable when one or more 4 kV emergency buses have one or more required Function 1, 2, or 4 (the Los.s of Voltage, the Degraded Voltage Low Setting, and the Degraded Voltage LOCA Functions, respectively) channels inoperab~e. or when one 4 kV emergency bus has one required Function 3 (Degraded Voltage High Setting) channel and one required Function 5 (Degraded Voltage Non-LOCA) channel inoperable, or when any combination of three or more required Function 3 and/or Function 5 channels are inoperable. In this Condition, the affected Function may not be capable PBAPS UN IT 2                        B 3.3-.195                                  Revision No. 77
 
LOP Instrumentation B 3.3.8.1
* BASES
  -~------------~-~-----------------
ACTIONS      Ll (continued) of performing the intended function and the potential consequences associated with the inoperable channel(s) are greater than those resulting from Condition A er Condition B. Therefore, only 1 hour is allowed to restare the inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of serv:lce time, the channel must be placed in the tripped condition per Required Action C.l.
Placing the inoperable channel in trip would conservatively c01Dpensate for the :lnoperabflity, restore design trip capability to the LOP instrumentation, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in a DG initiation),
Condition D must be entered and its Required Action taken.
The Completion Time is based on the potential consequences associated with the inoperable channel(s) and is intended to allow the operator time to evaluate and repair any d1scovered inoperabilities. The 1 hour Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
If any Required Action and associated Completion Time are not met, the associated Function is not capable of          _
perfonning the intended function. Therefore, the associated DG{s) is declared inoperabl:e imnediately. This requires entry into applicable Conditions and Required Actions of LCO 3.8.1 and LCO 3.8.2, which provide appropriate acttons for the inoperable DG(s).
SURVEILLANCE As noted at the beginning of the SRs, the SRs for each REQUIREMENJS Unit .2 LOP instrumentation Function are locat~d in the SRs column of Table 3.3.8~1-1. SR 3.3.8.1.5 is applicabl,e only to the Unit 3 LOP instrumentation.
The Surveillance a,re also modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of requfred Surveillance, entry into associated Conditions and Required Actions may be delayed for up to 2 hours provided: {a) for Function 1, the associated Function .maintains initiation capability for
* PBAPS UNIT 2                  B 3.3-196
{continued)
Revision No. 5
 
LOP Instrumentation B 3.3.8.1
* BASES SURVEILLANCE REQUIREMENTS  three  Gs; and (b) for Functions 2, 3, 4, 5, the associated (continued)  Function maintains undervoltage transfer capabi.l1ty for three 4 kV emergency buses. The loss of function for one DG or undervoltage tran~fer capability for the 4 kV emergency bus for this short period is appropriate since on1y three of four  Gs are required to start within the required times and b-ecause there is. no appreciable impact o.n risk. Also, upon comp1etion of the Surveillance, or expiration of the 2 hour allowanc~. the channel must be returned to OPERABLE status or tl:le applicable Condition entered and Required Actions taken.
SR 3.3.8,1.1 and SR 3.3,8,1,3 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perf~rm the intended function. Any setpofnt adjustment shall be consistent with the assumptions of the current plant specific *setpoi nt methodol og.y .
The Surveillance Frequency is contrelled under the Surveillance Frequency Control Progr~m.
A CHANNEL CALIBRATION is a complete check of the relay circuitry and associated time delay relays. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations, consistent with the assumptions of the current plant specific setpoint methodology, The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .
* PBAPS UN IT 2                    B 3.3-197                    Revision No, 86
 
LOP Instrumentation B 3.3.8.1
* BASES SURVEILLANCE  SR  3,3,8,1.4 REQUIREMENTS (continued)  The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the require.d actuation logic for a specific channel. The system functional testing performed in LCO 3.8.1 and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety functions.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR  3 , 3 , 8 , 1. 5 With the exception of this Surveillance, all other Surveillances of this Specification (SR 3.3.8.1.1 through SR 3.3.8.1.4} are applied only to the Unit 2 LOP instrumentation. This Surveillance is provided to direct that the appropriate Surveillance for the required Unit 3 LOP instrumentation are governed by the Unit 3 Technical Specifications. Performance of the applicable Unit 3 Surveillances will satisfy U'nit 3 requirements, as we lT as
* satisfying this Unit 2 Surveillance Requirement.
The Frequency required by the applicable Unit 3 SR also governs perfofrilan;ce of that **sR for Unit 2.
REFERENCES    1. UFSAR, Chapter 14.
* PBAP$ UN IT 2                                                  Revision No. 86
 
RPS Electric Power Monitoring B 3.3.8.2
* B 3.3 INSTRUMENTATION B 3. 3. 8. 2 Reactor Protect ion System. (RPS) Electric. Power Monitoring BASES BACKGROUND          RPS Electric Power Monitoring System is provided to isolate the RPS bus from the motor generator (MG) set or an al temate power supply in the event of overvoltage, undervoltage, or underfrequency. This system protects the loads connected to the RPS bus against unacceptable voltage and frequency conditions (Ref. 1) and forms an important part of the primary success path of the essential safety circuits. Some of the. essential equipment powered from the RPS buses includes the RPS logfc and scram solenoids.
RPS electric power monitoring assembly will detect any abnormal high or low voltage or low frequency condition in the outputs of the two MG sets or the alternate power supp1y and will de-energize its. respective RPS bus, thereby causing all safety functions nonnally powered by this bus to de-energize.
* In the event of failure of an RPS Electric Power Monitoring System (e.g., both i Ii series electric power monitoring assemblies), the RPS loads may experience significant
                    -effe-cts-from~the unregulated *power supply.--*Devfation-from - ---
* the nominal conditions can potentially cause damage to the scram solenoids and other Class IE devices.
In the event of a 1ow voltage condition, the scram solenoids can chatter and potentially 1ose their pneumatic control c:apa*bility, resulting in a loss of primary .scram action.
In the event of an overvoltage condition, the RPS l,ogic relays and scram solenoids may experience a voltage higher than their design voltage. If the overvoltage condition persists for an extended time period, it may cause equipment degradation and the 1ass of p1ant safety function.
Two redundant Class IE circuit breakers are connected in series between each RPS bus and its MG set,. and 'between each RPS bus and 'Its alternate power supply if in service.* Each of these circuit breakers has an associated independent set (continued}
* PBAPS UNIT 2                          B 3.3-199                      Revision No. 1
 
RPS Electric Power Monitoring B 3.3.8.2
* BASES BACKGROUND      of Class IE overvoltage, undervoltage, underfrequency (continued)  relays, tfme delay relays (MG sets only), and sensi.ng logic.
Together, a circuit breaker, its associated relays, and sensing logic constitute an electric power monitoring assembly. If the output of the MG set or alternate power -
supply exceeds predetermined limits of overvoltage, undervoltage, or underfrequency, a trip coil driven by this logic circuitry opens the circuit breaker,, which removes the assocfated power supply frQm service.
APPLICABLE
  -      -  - -    The RPS e,lectric power monitoring is necessary to meet the SAFETY ANALYSES  assumptions of the safety analyses by ensuring that the equipment powered from the RPS buses can perfonn its intended function. RPS electric power monitoring provides.
protection to the RPS components that receive power from the RPS buses, by acting to disconnect the RPS from the power supply under specified conditions that could damage the RPS equipment.
RPS electric power monitoring satisfies C'riterj,on 3 of the NRC Policy Statement .
* LCO            The OPERABILITY of each RPS electric power monitoring assembly-ts dependent on the OPERABILITY of-"the overvoltage; undervo]tage, and underfrequency logic, as well as the OPERABILITY of the as.sociated circuit breaker. Two electric power monitoring assemblies are required to be OPERABLE for each inservice power supply. This provides redundant protection against any abnormal voltage or frequency conditions to ensure that no single RPS electric power monitoring assembly failure can preclude the function of RPS components. Each tnservice electric power monitoring assembly's trip logic setpotnts are required to be within the specified Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Allowable Values are specified for each RPS electric:: power monitoring assembly trip logic (refer to SR 3.3.8.2.2).
_Jrip setpoints. are speciffed in design documents. The trip
                  *setpoints are selected based on engineering judgement and operational experience to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS~
Operation with a trip setting less c-onservative than the trip setpoint, but within its Allowable Value, is
* PBAPS UNIT 2                        B 3.3-200 (continued)
Revision No. l
 
RPS Electric Power Monitoring B 3.3.8.2
* BASES LCO          acceptable. A channel is inoperable if its actual trip (continued) setting is not within its required Allowab1e Value. Trip setpotnts are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., overvoltage), and when the measured output value of the process parameter exceeds the setpoint, the assoc1ated devi<:e changes state.
The overvoltage Allowable Values for the RPS electrical power 11onitoring assembly trip logic are derived from vendor specified voltage requirements *.
The underfrequency Allowable Values for the RPS electrical power monitoring assembly trip logic are based on tests performed at Peach Bottom which concluded that the lowest frequency which would be reached was 54.4 Hz in 7.5 to 11.0 seconds depending load. Bench tests were also perfonned on RPS components (HFA relays, scram contactors, and scram solenoid valves) under conditions more severe than those expected fn the plant (53 Hz during 11.0 and 15.0 second intervals). Examination of these components concluded that the components. functioned correctly under these conditions .
* The undervoltage Allowable Values for the RPS electrical power monitorfng assembly trip logic were confirmed to be.
acce-ptal>Te -through testing. Testing has -shown-the- scram*
pilot solenoid valves can be subjected to voltages below 95 volts with no deg.radatior:i in their ability to perform their safety function. It was concluded the RPS logic ~elays and scram contactors will not be adve.rsely affected by voltage below 95 volts si.nce these components will dropout under these voltage conditiohs thereby satisfying their safety function.
APPLICABILITY The operation of the RPS electric power monitoring assemblies is essential to disconnect the RPS components from, the MG set or alternate power supply during abnonnal voltage or frequency conditions. Since the degradation of a nonclass lE source supplying power to the RPS bus can occur as a result of any random single failure, the OPERABILITY of the RPS electric powe*r monitoring assemblies is required when the RPS components are required to be OPERABLE. Thi.s results in the RPS Electrtc Power Monitoring System OPERABILITY being required 1n MODES 1 and 2; and in MODES 3, 4, and 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies .
* PBAPS UNIT 2                      B 3.3-201 (continued)
Revision No. 1
 
RPS Electric Power Monitoring B 3.3.8.2
* BASES  (continued)
ACTIONS            AJ.
If one RPS electric power monitoring assembly for an inservice power supply (MG set or alternate) is inoperable, or one RPS electric power monitoring assembly on each inservice power supply i,s inoperable, the OPERABLE assembly will still provide protection to the RPS components under degraded voltage or frequency conditions. However, ,the re 11 abil 1ty and redundancy of the RPS Electric Power Monitoring System is reduced, and only a limited time (72 hours) is allowed to restore ,the inoperable assembly to OPERABLE status. If the inoperable assembly cannot be restored to OPERABLE status, the associated power supply(s) must be removed from service (Required Action A.I). This places the RPS bus in a safe condition. An alternate power supply with OPERABLE powering monitoring assemblies may then be used to power the RPS bus .
* The 72 hour Completion Time takes into account the remaining OPERABLE electric power mon.itorfog assembly and the low probability of an event requiring RPS electric power monitoring protection occurring during this period. It
* allows time for plant operations personnel to take corrective actions or to place the plant in the required
_co!l_~!ti ~f!._J_n _an --~~~rly ll!an_!le!'__and__ wt~_hout fEaJ 1~!191 ng _plant~-
systems.
Alternately, if it is not desired to remove the power s.upply from service (e.g., as in the case where removing the powe.r supply(s) from service would result in a scram or isolation.), Condition C or D, as applicable, must be entered and its Required Actions taken *
                      .6.J.
If both. power monitoring assemblies for an inservice power supply (MG set or alternate) are inoperable ~r both power monitoring assemblies in each inservice power supply are inoperable, the system protective function is lost. In this condition, I hour is allowed to restore one assembly to OPERABLE status for each inservice power supply. If one inoperable assembly for each in-service power supply cannot be restored to OPERABLE status, the associated power supply(s) must be removed from service within I hour (Required Action 8.1) . .An alternate power supply with OPERABLE assemblies may then be used to power one RPS bus.
(continued)
PBAPS UNIT 2                                  B 3.3-202                            Revision No. 1
 
RPS Electric Power Monitoring B 3.3.8.2
* BASES ACTIONS      .EL..1. (continued)
The 1 hour Completion Time is sufficie~t for the plant operations personnel to take corrective actions and is acceptable because it minimizes risk while allowing time for restoration or removal from service of the electric power monitoring assemblies.
Alternately, if it_ is not desired to remove the power supply(s) from service (e.g., as in the case where removing the power supply(s) from service would result in a scram or isolation), Condition C or D, as applicable, must be entered and its Required Actions taken.
Ll If any Required Action and associated Completion Time of Condition A or Bare not met in MODE 1 or 2, the plant must be brought to a MODE in which overall plant risk is minimized. The plant shutdown is accomplished by placing the plant in MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acc&ptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4-(Ref. 3) -and because the time spent in }10DE 3 -to per-form the necessary repairs to re.store the sys tern to OPERABLE status will be short. However, voluntary entry into MODE 4 rn ay be rn ad e as it i s al so an a cc e pt ab l e l ow - r i s k s tat e . The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
Ll If any Required Actii:m and associated Completion Time of Condition A or Bare not met in MODE 3, 4, or 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, the operator must immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Required Action D.1 results in the least reactive condition for the reactor core and ensures that the safety function of the RPS (e.g., scram of control rods) is not re~uired.
(continued)
* PBAPS UN IT 2                      B 3.3-203                              Revision No. 66
 
RPS Electric Power Monitoring B 3.3.8.2
* BASES  (continued)
SURVEILLANCE        SR  3.3.8.2.1 REQUIREMENTS A CHANNEL FUNCTIONAL TEST is performed on each overvoltage, undervoltage, and underfrequency channel to ensure. that the entire channel will perform the intended function. Any setpoint adjustment shall be consistent with design documents.
As noted in the Surveillance, the CHANNEL FUNCTIONAL TEST is only required to be performed while the plant is in a condition in which the loss of th.e RPS bus will not jeopardize steady state power operation (the design of the system is such that the power source must be removed from service to conduct the Surveillance). As such, this Survei1lance is required to be performed wnen the unit is in MODE 4 for~ 24 hours and the test has not been performed with1n the Frequency specified in the Surveillance Frequency Control Program. T.his Surveillance must be performed prior to entering MODE 2 or 3 from MODE 4 if a performance is required. The 24 hours is intended to indicate an outage of sufficient duration to allow for sched~ing and proper performance of the Surveillance
* The Note in the Surveillance is based on guidance provided in
______ Generi~_J~_tter _91-09 (Ref. _2).
The Surveillance Frequency is controlled under the Surveillance Frequency Contro1 Program.
SR 3.3.8.2.2 and SR 3.3.8,2.3 CHANNEL CALIBRATION is a comp1 ete check of the re ray circuitry and applicable time delay relays. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted between successive calibrations consistent with the plant design documents.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR  3.3,8.2,4 Performance of a system functional test demonstrates that, with a required system actuation (simulated or actual) signal, th logic of the system will automatically trip open the associated power monitoring assembly. Only one signal PBAPS UN IT 2                        B 3.3-204                    Revision No. 86
 
RPS Electric Power Monitoring B 3.3.8.2
* BASES SURVEILLANCE    SR  3,3.8.2.4    (continued)
RE QUI REM EN TS per power monitoring assembly is required to be tested.
This Survei:llance overlaps with the CHANNEL CALIBRATION to provide complete testing of the safety function. The system functional test of the Class lE circuit breakers 1s included as part of this test to provide complete testing of the safety function. If the breakers are incapable of operating, the associated electric power monitoring assembly would be inoperable.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
REFERENCES      1. UFSAR, Section 7.2.3.2.
: 2. NRC Generic Letter 91-09,. "Modification of Survei 11 anee Interval for the El ectri cal Protective Assemblies in Power Supplies for the Reactor Protect 1on System."
* 3. NEDC-32988-A, Revision 2, Technical Justification to*
Support Risk-Informed Modification to Selected Required End States for .B\i/R Pl ants,. De_cemb:ec _2_00_2. _
PBAPS UN IT 2                      B 3.3-205                          Revision No. 86
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* B                        TABLE OF CONTENTS pag,e(s)      1.................................................: .. -.................................... -................... Rev 145 ti ............................................................................................-.**.*..*.*.*.**.._Rev 145 lU ............ ,...............................................................................,............... Rev 150 B 2.0                    SAF,ETY LIMtrs {Sls) page(a)      ~:tl::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::'.:::::~:::::::::::::::::;::::::::::::::::: l~
2.0-3 ......................................................................................... ,............. Rev 157' i0-4 ..........-............................................................................................. Rev 1G7 2.0-5 ............................ ,................... , ........................................................ ~ev 75.
2.0-6 ....................................................................................................... Rev 128 2:o-7,.. ............................................................................................ , .......... Rev 75 2.0-8, ...................................................................................................... Rev 148 2.0-9 ............................................................ :..*...... , ........... ,....................-.. f:tev 75 2.0-1,0 .......... :................................................................. ,.........................,Rev 148 B 3.0                    LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY page{s)      3.0-1 ................................................................................................. ,.... ,Rev            156 3.0-2: ................................. , ...............................................................*...... Rev        152 3.0-3, ...................................................................................................... ,.~v            162 3.0-4 ........................................................................................................ Rev            141 3.0..S ........................................................................................-. .. : ........... Rev 141 3.0-Sa .................................... , .......................... ,..................................... Rev 141
                                        '3.0-5b .................................................................................... ,, .. ,............ Rev 1'41 3.0-6 ............. , ........................................................................................... Rev 52,
                                      , 3.0-7 .... - .............................. , .................................................................. Rev 141
  -------.- ___ L........_  ~-  ... ~-a.o:ra..=-::........ ~ ..........~---****"******************--*-********************************~ ....... ~ ......... Re\i 141        -
3.0-9 ....................................................................................................... Rev 145 3.0-9a ............................................................................ _ ...................... ,Rev 1'45 3,0-9b ...................... :... ,: ......................................... ~ ... : ........................... Rev 156 3.0-9c .....-.... ,............................ , ........................ , ..................................... Rev' 156 3.0-9d ........................... , ......................................................................... Rev 156 3.0-9e ..................................................... _............................................... Rev 156 3.0-10 ...................... ,... ,.......................................... , ...............................:R~v 140 3.0-12 ..........~ .......................................................................... , ............... Rev 141 3.0-13 ............ ,.. , ..................................................................................... Rev 141 3.0-1'3a .......................................... ,............................ , ........................... ,Rev 1'4f 3.0-14 ....................................................................................... , ...............,Rev 5!l 3,0-1:fl , .................................................. *-******* .......................................... Rev 52 B 3.1                    REACilVlTY CONTROL SYSTEMS page(s)'      3.1-5 .................... ., ........ , .............................................. ,. .......................... Rev 72
                                        '3. 1'-6 ................................................. ,.. ,., ............................................ _ .... Rev 12 3.1-7 ...._................... ,.. , .................... *-*****"******* ..********* .. **** ........................ Rev 72 3.1-8 .................................... , .............. ,. ............................................. ,.... Rev 113 3.1-9 .... :.................. ,..... :........... - ............ :.... ,................................ ,...... , .. Rev 113 3.1-1,0 ........................................................................._., ............................ Rev: 94 3.1-1'1 ................. , ..................... ,..................................................._.......... Rev 113 3.1-14 ....................................................................................................... Rev 49 "3.1-15 ,..... ,.................. , .......... ,__. ..... ,............................ ., ................ ,...............Rev' 2 3.1-16 ............................... - ..................................................................... .,Rev 79
* PBAPS UNIT2 3.1-17 ............. ,...... , .................. , ... , ....................... - ................... , ............... R$V 63 Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES P(\GE REVISION LISTING
* 83.1    ~CTMTY CONTROL SYSTEMS (continued) page(s) 3.1-18 ............................... .'....................................................................... Rev 63 3.1-19 ....................................................................................................... Rev 86 3.1-20 ....................................................................................................... ,Rev 79 3.1-21 ................................................................... ,................................... Rev 63 3.1-23 ........................................*...............*.............................*.........*...-... Rev 49 3.1-25 ....................................................................................................... Rev 57 3.1-26 *********************************-******************************************************************** Rev 86, 3.1-27 .....*................................................................................................* Rev 57 3.1-28 *.*...............**.................. , ...... , ......................................................... Rev 72 3.1-29 ....................................................................................................... Rev 49 3.1-31 ................*...........................*........................................................... Rev 2 3.1-32 ........................................................................................................ Rev 2 3.1-33 .................................................................*....................*..............* Rev 86 3.1-34 ....................................................................................................... Rev 76 3.1-36 ..................................................................................................... Rev 114 3.1-35a ..................................................................................................... Rev 63 3.1-36 ................*................................................................................... ~.Rev 63 3.1-37 ..............................................................................~ ........................ Rev 86 3.1-36 ....................................................................................................... Rev 61 3.1-39 .......*..........................................................................*.................. Rev 114 3.1,-40 ...............................................*.*.*.*........*..*.*...*.*......................*.... Rev 114 3.1-41 ..................................................................................................... Rev, 114 3.1-42 .................................................................................. _................. Rev 114 3.1-43 .................................................. , .....*.... ,................*...................... Rev 114 3.1,-44 ..................................................................................................... Rev 114
* '                  3.1-46 ***********-****************************************************************************************Rev 114 3.1-46 ...................................*......*.......*........................... :.*......... ;....*..... Rev 140 3:"1 ~~=***************** ****** ...........................................=::-...............:::........ ~V-13(,
3.1-48 ................................................................................................... ,... Rev 75 3.1-49 *******************************-**********************-******* .. *************************************Rev 57 3.1-60 ....................................................................................................... Rev 57 3.1-51 ....................................................................................................... Rev 86 3.1-52 ..............................*....-... ************************************************************ ..... ,Rev' 86 8 3.2    POWER DfSTRIBUTION LIMITS page(s) 3.2-1 .... ,.................................................................................................... Rev 49 3.2-2 ...................................................................................*..................... Rev 49 3.2-3 .....*....... ;. ........................................................................................ Rev 143 3.2-4 ....................................................................................................... Rev 143 3 .2:..5 .....................................................................*................................. Rev 143 3.2-6 ....................................................................................................... Rev 157 3.2-7 ***-************************************************************************'"************************Rev 157 3.2-8 .................*.......*...*......................*......*........ ,**....*..*......*..*... ,, ....... ,. Rev 143 3.2-9 ....................................................................................................... Rev 143 3.2-10 ..................................................................................................... Rev 143 3.2-11 ................................................................................ , .* , .......*.... ,.... Rev 101 3.2-12 ..................................................................................................... Rev 143 3.2-12a ............................................................................................. , ..... Rev 143 3.2-13 ......................................................... ,....................... , ..........*.......* Rev 143 3.2-13a .................................................................................................. Rev. 143
                                                                                                                                  ,r PBAPS UNIT2                                                JI                                                      Revision No 157
 
PBAPS UN'IT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* 83:3    INSTRUMENTA ilON page(s) 3.3-1 ........................................................ :................................. :......_...... Rev 134 3.3 6 (Inclusive) ..................... :............................................................ Rev 24 3.3..7 ....................................................................................................... Rev 124 3.3-8 ******************************************* ................ , ....*.... ,................................. Rev 143 3.3-9 ********j*****~**********************'*****il**** . ****li: ............. ~********* . ********* . "************il*Rev 143 3.3-10 ....................................................................................................... Rev '36, 3.3-11 .............., ........................................................................................ Rev 36 3.3-12' ....................................................................................................... Rev 50 3.3-12a ............ ,.......... - ............................................... ,. ......................... ,Rev '143 3.3-12b ..................................................................................................,Rev 143 3',3-12c ........................................................................................... ,......* Rev 123 3.3-17 ......................................................................................................-.Rev 87 3.3-18 ............ *-****** .. ********* .. *************** ........................~ ........................... Rev 143 3.3-19 .................................................................................................... .,Rev 143 3.3-28 ........................................................ ,............................................ Rev 134 3.3-21 .................-....................................................................................,Re'/ 134 3.3-23 ..................................................................................................... Rev 149 3.3-23a .........................................................................-......*..*................ Rev '149 3.3-24 ............. ,......................................... ,.....*...........*............................. Rev 50 3.3-26 ....................................................................................................... Rev 50
                  '3.3-26 ............................. *-******** .. *************************************************************'Rev 36 3.3-27' ..................................................................................................... Rev 123, 3.3-27a ............................ - ..................................................................... Rev 123 3.3-27b .................................................................................................. ,Rev 143 3.3-28 ..................................................... ,....................... ,....... , ........*.....* Rev 149 3.3-28a ............................................................. ., .................................... Rev '149 3.3-29 ................:.................................................................................... Rev 143'
:ta.30 ...................... -.:....... :..................................................................... Rev 114 3.3-31 ........................... -.--~- -_ - - - . , .............................. -.............. Rev1l4--
3.3-32 ........... ,.................... ,............. :..-.:..................... ;........... :................. Re9' 114 3.3-33 ..............._, ..................................., ................................................. Rt;tv 162 3.~ .. ,.................................................................................................. Rev 143' 3.3-35,. .... ,.......................... ,.................................................................... Rev 123 3.J;..36a ................................................................................................... Rev 123 3.3-35b ...................................... ,............................................................ Rev 143 3.3 40 (incb,1slye) ...... :.:.................'. ........_........................................_... Rev 24 3.3-41 ..........*.**..... ,...................., ...*..*.........*...........*....... ,......... ,....... ,,, ..... Rev 86 3.3-42 ..........*........................... ,.... ,.................................................... ,...... Rev 86 3.3-43 ....................................................................................................... Rev 86 3.3-44 ..............................................................._..... ,.................................. ,Rev 86 3.3-45, ..........._....................................................... , .................................... Rev 36 3.3-46 ................. *-************ .. ******************* .................................................. Rev 36 3.3-48 ................................ ,.*..*..* ,............ ,................ :............ ,...... , .... ,.. ,.Rev 143 3.3-49 ....................................................................................................... Rev 63 3.3-52 .............. :.............................. ,............. , .*.*....*...*. ,.*.....*. , ......*... , ........ Re\/ 86 3.3-53 ....................................................................................................... Rev            86 3.3-54 ...........*........... ,..............,*. ,...................................................,......... Rev          86 3.3--5$ ....................................................................................................... Rev          86 3.3..66 ................... ,. *..... , ... ,, ................ ,... ,.......................... ,...................... Rev  86 3.3-57 ....................................................................................................... Rev            6,1 PBAPS UNIT2                                                  Ill                                                          Revision No. 157
 
PBAPS UNIT 2 :- LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* 83.3        INSTRUMENTATION (continued) page(s)      3.3-58 ...........*........._................................................................................ ,Rev 146 3.3-59 ..................................................................................................... Rev 143 3.3-60, .................................................. ,.....*....... , .................................... Rev 143 3.3-62 *.....*.........*....*.....*.... -.....*...........................*. , ............................**... ~8V 143 3.3-63 ..............................*.......*................................................*....*.......*.. Rev ,80 3.3-64 ............................................................................................-......... Rev 143 3.3-67 .. ,..*..*......................*...............................*.........*.*............................. Rev 7 3.3-68 ........................................................... ,... ,......................................... Rev    3, 3.3-69 ,., ...........................................................*..................*........*............_Rev 57 3.3-70 .........*..........*.......*........................ ,.............................................. ,.. Rev 56 3.3-71, ....................................................................... , ...*........................... Rev 62 3.3-72 ........................................................... , ............................................. Rev 3 3.3..-73 ......................................................................................................... Rev 3 3.3-74, .......................................................... , ............................................ Rev 86 3.3-76 .,, ....................................................................................................Rev 86 3.3-76 ..................................................................................................... Rev 132 3.3-n ********************~********************************* .. ******* ................................. : .... Rev 132 3.3-78 ....................................................................*.................................. ,Rev 52 3.3P79 ......................................................................... ,........................... Rev 132 3.3-80.... -., ............................................ ,...*.... ., .............................. Rev 132 3.3-81 ................. ,. ......*................................ ,., .......... ,.........* ., ........ Rev 132 3.3-82 ..................................................................................................... Rev 132 3.3-83 ..................................................................................................... Rev 115 3.3-89 ..............................................*......................................... ,....*........* Rev 86' 3.3-90 ....................................................................................................... Rev ,86 3.3-91 .....................................*...........*.... , ...*.... , ..*..................................*. Rev 86 3.3-91a .................................................................................................. ,Rav 137 3.3-91b .............. , .................................................................................... Rev 143
--- -- - -- - ~-~ -----r-- -~ -- -""' --a:a:91c ..."\ ...................*..*....*.................*.....*......*....................; ... :~ ..... :~.--::-:::Rev~-
3.3-91 d *........*............................... ,......*.... , ............................................. Rev 143 3.3-91e .................................... ,.............................................................. Rev 143 3.3-91f ..................................................................................................... ,Rev 67 3.3-91 g ................................................................................................... Rev 143 3.3-91 h ................ :......................................... - ..........................*..........*..* Rev 86 3.3-911 ................................................................................................... Rev 143 3.3-91j ............................................. ,..................................................... Rev 143 3.3-98 ....................................................................................................... Rev 21 3.3-99 .... ,. ...... , .................................. , .*....... ,.. ,*....................................... Rev 146 3.3-100 .....*...............................*. ,*....*.................................. ,.................. Rev 145 3.3-101 .................................................................. ,... ,, ........................... Rev 146 3.S-102 ................................................................................................... Rev 146 3.3-103 .. , ..... ,.......................................................................................... Rev 145 3.3-104 .. , ................................................................................................ Rev 146 3.3-106 ***************************************************************************************************Rev 145 3.3-111 ***************************************-********************************************* ............... Rev 78 3.3-117 ................... , ............................................................................... Rev 145 3.3-118 ................................................................................................... Rev 145
                                      '3.3-120 ................................................................................................... Rev 146 3.3-122 ................................................................................ ,.................. Rev 145 3.3-124 ..........*.. , .......................-................................................................ Rev 68 3.3-125 ..........................................*.......* '.................................................. Rev 83 3.3-127 ...-...................................................... , ........................................... Rev '86
* PBAPS UNIT2                                                        ,Iv                                                          Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVIS'ION LISTING B 3.3    INSTRUMENTATION (cohtlhued) page(s)    3.3-128 ................................. ~********************************************************* .. *******,Rev 86 3.3-129 ..................................................................................................... Rev 86 3.3-138 .*........*.....*.................*................................ ,.......*..............*.......... Rev 86 3.3-139 ....*....*, .................... , .............*.......***.........*...................*............... Rev 86
                                ,3.3-140 ....................*..................................*......................*................*....* ,Rev 86 3.3'-140a ..*..*............................*...........*....................................... , .......*.. Rev 146 3.3-140b ......*.*.*........................................... , ................... , ...*.................. Rev 145 3.3-1AOc ... , ........ ,.....................................*..................................*........... Rev 145 3.3-140d ................................................................................................. Rev 145 3.3-140e ..*........*.*....*.......*..*....**..............................*.............................. Rev 145 3.3-140f ..*........................*...*......*.. :.........................*..*. , ......................... Rev 146 3.3'-140g ................................*.*.................*. , ....*........................ :............ Rev 145' 3.3-140h .........*. ., .................................................................................... Rev 146 3.3-1401 .................................................................................................. Rev 145 3.3-140J .................................................................................................. Rev 145 3.3-141 ........................*...*...............*.......*..*...........................*............. ,,Rev 134
                                '3.3-142 *...................................................*............**.................................. Rev 48 3.3-143 ..................................................................................................... Rev 48 -
3.3-144 ......... ~ ......................*...........*.....*.................................................. Rev 57 3.3-145 ..................................................................................................... Rev f$7 3.3-147 ...*...........................................................................................*... Rev 143 3.3-148 ................................ , ..... ,............................................................ Rev 1,34 3.3-149 ............ :....................*................................................................. Rev 134 3.3-149a ..*..*........-.*...............................*................................................... Rev 75 3.3-150 ...*...................*......*...................*...........................*..... , ........* , ..... .,Rev 76 3.3-151 ...................*.........*.... , .....*...*........................................................ Rev 20
- - ------ - -------- ------- ---3.~166 ..... ,......... ~*************~****************************************** .. *************************Rev_32 ________ _
3.3-166 .............................................._.....................*................................. Rev 76 3'.3-157 ***************************************************-*************************,*******************"'Rev 136 3.3-168 ....*... , .......................................................................................... Rev 145 3.J..169 ,.*......... ,..................................................................................*.*. Rev 146 3.3-159a .......................... ,........................................................................ Rev 57 3.3-160 ...*....*.*..*....*...................*....*..........*.........................*.................... Rev 57 3.3-161 .............................. , ................ , .................. ,......... , ................... ,.... Rev 48 3.3-162 ....*....................................... ., ......... , ........*.............................*...... Rev 46 3.3-165 *........* ,, .. ,, .........................*........................................................... Rev 86 3.3-166 ...................................................................*........ , ...................... Rev 134 3.3-1'67 ..................................................... ,...*......................................... Rev 114 3.3-168,.........-. ..................*................*....*...............*............*.................. ,Rev 143 3.3-1'69 -171 (Inclusive) .............................. ,..................*........*................ Rev 1 3.3*172 ................*.........*................... ,., .. ,............................................... Rev 145 3.3-173 ...............................................................................*......................* Rev 1 3.3~174 .*..............*.....................................*....*.. ;.*.*.*..*....*...................... Rev 145 3.3-176 .............*.*......... , ..................................................*.......................... Rev 1 3.3-176 ................................................................................... ,............... , .. Rev 1 3.3-177 ...._. ..........................* ,...... , ............ , ................................................ Rev 86 3.3-178 ....*.........................................*.*.......................*.........................*.. Rev 86 3.3-179 -181 (inclusive) ..............*...*...........*....................................... ,, .... 'Rev 1 3.3-182 ..........*. , ...................................................................................... Rev 145 3.3-183 ..................... , ................................... ,... , ......................................... Rev 1 3.3-1'84 ............................................................................................ , ...*.... Rev 86
* PBAPS UNIT2 3.3-186 .,, ...... ,........................................................................................... Rev 86 V                                                          Revision No 157
 
PBAPS UNIT 2 - LlCENSE, NO. OPR-44 TECHNICAL SPECrFICATIONS BASES PAGE REVISION LISTING
* B3.3    INSTRUMENTATION (cohtinue(I) page(s)  3.3-186 ..................................................................................................... Rev 86 3.3-1'87 ....................................................................................................... Rev 6 3.3-188 ************* .. ************** .. ***** .................-............................................... RQV 88 3.3-189 ...**..-...... ,.......................... ,....-....................................................... Rev '88 3.3-1'90 ....................................................................................................Rev 88 3.3-191 - 194 (Inclusive) ....... : ........: ........................; ..................................'Rev 5 3.3-195 ...................... ;..................................................................-.._....*...*. Rev n 3.3-196 .................................................................... , *.......... ,, .....*..*.*.....*.... Rev 5 3.3-197 ..................................................................................................... Rev 86 3.3-198 ..................................................................................................... Rev 86 3.3-199 ......... :......: ...................................................................................... Rev 1 3.3-200 ....................................................................................................... Rev 1 3.3-201 ........................................................................ *-****************************Rev 1 3.3-202 ,............ *-************ .. **** .. **** .. ************************************ ......................... Rev 1 3.3-203 ..................................................................................................... Rev 66 3.3-204 ..................................................................................................... Rev 86 3.3-205 ..................................................................................................... Rev 86 B 3.4    REACTOR COOLANT SYSTEM (RCS) page(s)  3.4-1 ..................................... :...................................................... ,.......... Rev 137
:3.4-2 ....................................................................................................... Rev 137 3.4-3 ....................................................................................................... Rev 123 3.4-4 ***************************** .......... ,................................................................. Rev 50 3.4-5 .............................................................................. : ........................ Rev 123 3.4-6 ............... ,.., ......*...*.....**..0 ..........................................-*********************** Rev 50
-* - - - - - - - ~-~- ~. - ~ -..3.4..Z... ........................................... _........... _-*****.* -_****~**********--*--***** ........ Rej{__j2L~~~
3.4-8 ............................................................................................ ,.......... Rev 123 3.4-9 ....................................................................................................... Rev 123 3.4-10 ., .... ,:...*. ,............*.. - ...................................................... ,............... Rev 123 3.4-14 .......... ,.......................................................................................... Rev 143 3.4-16' ................................... '"'*********** .. ****,*** .. ********** ...*,****************"***,**** Rev 114 3.4-16 ..................................................................................................... Rev 148 3.4-16a ............... m************ ..................................................................... Rev; 142
* 3.4-17 .... ,................. ,.......................................... ~******** .. *************************Rev 140 3.4-1'8 ........................................................................... , .*..... ,................. Rev 148 3.4-23 .......................................... ,.*............*...... , .... ,.. *******************~*** ...*,***Rev 86 3.4-24 ....................................................................................................... Rev ,93 3.4-25 .......*...*.*....*..... , .................................................. ~*****~*********************Rev 93 3.4.26 ....................................................................................................... Rev 93 3.4-26a ... .,.......... ;....................................................................... ,........... Rev 152 3.4-27 .......................................... ,..... ,....................................................... Rev 86 3.4-28 ....................................................................................................... Rev 93 3.4-29 .........*.........................**. ,................*..*........ ,*.... ,*...............*.......*.... Rev 75 3.4-30 ....................................................................................................... Rev 75 3.4-31 ..................................................................................... ,, .........*...... Rev 75 3.4.:32 ., ...... ,.,,, .......................................................................................... Rev 86 3.4-34 ..**.............*......... :...................................... , .... ,...*........... ,............. R$V 126 3.4-35 ............... ,............*................... ,...................................................... Rev 52 3.4-37 .............................. ,..................................................................... , Rev 126 3.4-37a ...................................... .,, .......................................................... Rev 12.7 3.4-37b .......................... , ................................................................... , .... Rev 12s PBAPS UNIT2                                                  vi                                                          Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE RE\IISION LISTING 8 3.4    REACTOR COOLANT SYSTEM (RCS) (continued) page(s)  '3.4-39 ..................................*........*............ , ............................................ Rev 126, 3.442 ....................................... ~ ............................................................ Rev 127 3.4-42a ................................................................................................... Rev 126 3.4-43 ..................... ,;......................*.................*..............*...*....*.*........... Rev 10:i!
3.4-44 ..................*...*......*.*.............*..............................*.*..*................... ~ev 102 3.4-46 .....**...... , ....................................................................................... Rev 102 3,4-46 ................................................................................................. ,... Rev 102 3.447 ********************************................................................ , .......... , ......... Rev 102 3.448 ............................................ ,. .............*.....................*...*............... Rev 102 3.4-49 , ............................ ,....................................................................... Rev 102 3.4-50 ............................................................................. , ............... ,....... Rev 102 3.4-51, ..................................................................................................... Rev 102
                    '3'.4-52 .....................*..............*.................................................................. Rev 49 3.4-53 ..................................................................................................... Rev 114 B 3.5    EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM page(s). 3.~1 ...........*.............*..........................................*.................................* Rev 145 3.6-3 ..................... , .................................................... ,., .........*.....*.......... Rev 110
                    '3.5-4 ..*.*......*.................*...........................**...............*._........................... Rev 147 3.5-5 ..... ,.... ,............................................................................................ Rev 126 3.5-6 ....................................................................................................... Rev 145
                    ,3.5-6a ..........................................................-.............................*....*.......... Rev 96 3'.5-7 ........................................................................................ , .*.............. Rev 89 3.~ ................................................................................................ , ...... Rev 101 3.5-9 ......*......*...*........... , ......................................................................... Rev 126
              ~-3~.5-10 .............. ,............................................ ,.............. =** .................... Rev 127 _- ~ - - - -
3.5-10~ ................................................... .,*.*......... :.................................. Rev 126 3.5-11 .............................................................: ......................................... ,Rev 86 3.5-12 ..................................................................................................... Rev 140 3.6'-13 ....................................................................................................... Rev 99 3.5-14 ........................................................................................_.............,Rev 143 3.5-15 ....................................................................................................... Rev 86 3.6'-16 ....................................................................................................... Rev ,86 3.'5-17 ...................................................... , .............................................. Rev 101 3.5-18 ............ ., ...... ,.......................... , ............ , .... , ................................... Rev 145 3'.5-19 .................., ............................................................... , .................. Rev 145, 3.5-19a -,23 (Deleted)'................... ,........................................................ Rev 145 3.5-24 ..................................................................................................... Rev 145 3.5-25 , .................................................................. , ................................. Rev 146
                    '3.6-26 ....................................................................................................... Rev 66 3.5-27 ..................~ ............................................ u,**** .. *** .......................... Rev 127 3.5-27a ., .............................................................. ,. .. , ........ , ........ ,........ , ... Rev 126 3.5-28 ................................................ , ........ , ........................................... Rev 143 3.5-29 ......................................................._........ ,....................................... Rev 86 3.5-30 .................................. ,.........._................................................... ,. ..... Rey 66 J.5-31 ............................-...... , .................................................................. Rev 146 3.6-32 , .................................................................................................... Rev 1'45 3.5-32a ............... ,................................................................................... Rev 145 3.(;-33 ..................................................-: .................................................. Rev 145 3.5-34 ................................................................................................... ,. Rev 145 3.5'-35 ............ , ......................................................................... ,..*.... , ...... Rev 1'46 3.5-36 .............................. ,...................................................................... Rev 145 PBAPS UNIT2                                                vii                                                            Revisiofl No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
** 8 3.5    EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTO~ CORE ISOL.ATION COOLING (RCIC) SYSTEM (continued) page(s)      3.5-37 .....................................................................................................Rev 146 3.5-38 ..................................................................................................... Rev 145 3.6-39 ............................................... - .................................................... Rev 145 B 3.6    CONTAINMENi SYSTEMS page(s)      3.6-1 ....................................................................................................., ... Rev 27 3.6-2 ................ , ...................................................................................... Rev 114 3.6-3  *****************************************************************;***************************************Rev 66 3.6-4 ............................................................................................ ,.........*.. Rev 86 3.6-5 .......................................................................................................Rev 118 3.6-7 ....................................................................................................... Rev 114 3.6-11 ....................*.................*.......*.*...................*....*......**.*.*.*...............*.Rev 6 3.6-12 ........................................... , ........................................................... Rev 86 3.6-1'3 ...................................................................................., ...............* Rev 114 3.6-16 .......................................................................................................,Rev 91 3.6-17, ..*.........*.*....*.......*.........................................................***............. Rev 144 3.6-18 .................................................................., .....................*............ Rev 146 3.6-20 ..........................................................................., ........................... Rev 57 3,6-21 ......................................................................'................................. Rev 67 3.6~22 ....................................................................................................... Rev 57 3.6-23,. ..............................**.................**..*........*..*....,. ...................*......... Rev 144 3.6-23a ............ ,...................................................................................... Rev 145
* 3.6-24 ....*...**...............*..........*.... ,, ............................................................ Rev 91 3.6-25 ....................................................................................................... Rev 86 3.6-26' ....................................................................................................... Rev 86
                    -----a-:s:;21*.......-..........................................................................,........... ~ e v 1 ~
3.6-28 ....................................................................................................... Rev 86 3.6-28a .......... ,, ...................*................................*...................*.............. Rev 152 3.6-29 ....................................................................................................,Rev 144 3.6~ .................................................................................................... Rev 114 3.6-31 ..*.......*.............*................*.........*.***........*.............*.., ..*.............*... Rev 18 3.6-33 .................................................................................................... Rev 1 t4 3.6-35 ........................................ , .....................................................:......* Rev 91 3,6'-38 ..................................... ~ ....................................... ,..... , ......*....*...*. Rev 66 3.6-39 ...................................................................................................... Rev 91 3.6-40 ....................................................................................................... Rev 86 3.6-41 *.....*..*..*....*....*......*.. ,......................................, ............................... Rev 86 3.6-43 .......................................................................................................,Rev 44 3.6-45, .......................................................................................................,Rev 66 3.6-46 ..................................~****************** .. *********** ..................................... Rev 86 3.6-47 ....................................................................................................... Rev 86 3.6 61 (l!iclusive) .............................................................................. Rev 24 3.6-52 ........~ ............................................................................................ Rev 114 3.6-54 .*....... :. ........... *-****************************************************************************  Rev  145 3.6-56 .......... , ..............*. , ....*.................................*.....***........................*... Rev 86 3.6-66 ...............................*..*............ ,..................................................... Rev 114 3.6-57 .....................................................................................................Rev 126 3.6-58 ............... , .. , .................................................................................. Rev 151 3.6-59 ....*...............: ................................................................................ Rev 140 PBAPS UNIT2                                                    viii                                                      Revision No. 157
 
PBAPS UN,I.T 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING
* 133.S-    CONTAINMENT SYSTEMS (continued) page(s)      3.6-59a ......... *-***************************************************************************************Rev 127 3.6-59b ................................................................*....*...........................*. Rev 126 3.6-60 .........................*.......................... :................................................ Rev 114 3.6-6-1 ............................................*.........*.*.. , ......................................... Rev 126 3.6-62 ..................................................................................................... Rev 151 3.6-63 ..................................................................................................... ~ev 130 3.6-638 ............................................................ , ..................~ ................... Rev 127 3:~b ........................*..... ,.................................................................... Rev 1'26 3.6-63c ...................... :.................................................................... ,*..*... Rev 126 3.6-63d ................................................................................................... Rev 126 3.6-63e ............................................................................. ,..................... Rev 151 3.6'-63f ....................................................... , ............................................ Rev 130 3.6-63g .................................. , ................................................................ Rev 1*27 3.'6-63h ................................................................................................... Rev 126 3.6-64 ............................................................... , ....................................... Rev 80 3.6-70 ....................................................................................................... Rev 80 3.6-72 ....................................................................................................... Rev 86
                        '3.6-73 ...* ,...................... ,........................................................................... Rev 75 3.6-74 ........................................................ ,......*.....................*. ,.....*....... Rev 145 3.6-75 ..................................................................................................... Rev 145 3.6-76 ...................................................................: ................................. Rev 120 3.6-77 ....................................................................................................... Rev 97 3.6-78* ....................................................................................................... Rev 76 3.6-79 ...................-.................................................................................. Rev 146 3.6-81 ......................................................... ,.............................. ,.............. Rev 57 3.6-82 ................................................. ,, .................................................. Rev 145
        -~ --~ ---------3.6-83.. .................................................................................................... ReY-1-40..~ --------~
3.6-84 ....................................................................................................... Rev 86 3,6-87 ..................................................................................................... Rev 146*
3.6-88 ......................................... , ........................................................... Rev 145 3.6-89 .......... ,........................................................................... , .............. Rev 146 3.6-90 ................................................, ...................................................... Rev 86' B 3.7    PLANT SYSTEMS page(s)      3.7-1 ....................................................................................................... Rev*114 3.7-2 ...................................................................................... , .*.............. Rev 114 3.7-3 ....................................................................................................... Rev 144 3.7-4 ....................................................................................................... Rev 161 3.7-6* ...................................................... :........................... ,...... , ............. Rev 151 3.7-Sa ........................................ ,............................................................ Rev 114, 3.7-6b ..................................................................................................... Rev 114 3.7-6 ........................................................................................................... Rev 4 3'.7-7 .................... , .................................... , ............................................. Rev 109 3.7-8 .................................... ,.............................................. ,................... Rev 109 3.7-9 .................................................. ., ................................................... Rev 109 3.7-10 ............................................................................. , ......... ,............... Rev 86 3.7-11 ....................................................................................................... Rev 67 3.7-12 ................................................ , ..................................... , ................ Rev 92' 3.7-13 ..................................................... ,................................................... Rev 1
* PBAPS UNIT2                                                      ix                                                        Revision No 157
 
PBAPS UNIT 2 - LICENSE NO. OPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING .
* B 3.7    PLANT SYSTEMS (continued) page(s)  3.7-14 ................................................................. , ..................................... Rev 86 3.7-15 .................................................................................................... ,Rev* 116 3.7-16 ..................................................................................................... Rev 116 3.7-16a ............................................................................. , ..................... Rev 116_
3.7-16b .............................................. - ................................................... Rey 121 3.7-17 .................................................................. , .. ,............................... Rev 145 3.7-18 .................................... ,................................................................ Rev 116 3.7-19 ............................................................ , ........................................ Rev 145 3.7-20 ..................................................................................................... Rev 145 3'.7-20a ........._.......................................................................................... Rev 116 3.7~21 ..................................................................................................... Rev 121 3.7-23 ....................................................................................................... Rev 66
: 3. 7-24 ... .................................................................................................... Rev 86 3.7-25 ................................................... , ................................................. Rev 143 3.7-26 ..................................................................................................... Rev 143
: 3. 7-27 ...................................................................................................... Rev 143 3.7-28 ................... ,................................................................................. Rev 143 3.7-29* ....................................................................................................... Rev 75 3.7-30 .......................................................................... , ........................... :Rev 86 B 3.8    ELECTRICAL POWER SYSTEMS page(s)  3.8-1 ....................................... ., ................................................................ Rev 82 3.8-2 ........................................................................................... ,............. Rev 90 3.8-2a ........................................... , ........................................................... Rev 90
            - - -3.0;.:t ....................................................................................................... Re.Y~1~14_ _ __
3.8-5 ............................ , ............. , .............................................................. Rev 73 3.8-6 ................................................................................. , ....................... Rev 52
                  .3.8-7 ........................................................................................................... Rev 5 3.~ ............ ,............................................................................ , ...... , ........ Rev 85 3.8-9 .............................................................. ,.......................................... Rev 85 3.8-10 .......................... , .............................................................................. Rev 5 J*.8-11 ....................................................................................................... Rev 60 3.8-12 ........................................................................................................ ;Rev 1 3.8-17 ................................... , ........................ _......................................... Rev 66 3.8-t8 ....................................................................................... , ............... Rev 71 3.8-19 ....................................................................................................... Rev 86 3.8-20 ................. ,..................................................................................... Rev 86 3.8-21 .................................................................. ,... ,.............................. _ Rev 86 3.8-22 .......................................................... , ......... , .................................. Rev 86 3.8-23 .......................................... _.......................................................... , Rev 86 3.8-24 ........................................................... ,.................................. *-****Rev 139 3.8-26 ......................... ._. .............................................................................. Rev 1 3.8-26 .......................... ,............................................................................ Rev 86 3.8...27 ........... , ................................................................... *-********** ........... Rev 86 3.8-27a .......................................................................................... , ........... Rev 57 3.8-28 ...................................................................................... ,... , ............ Rev 86 3.8-29 ....................................................................................................... Rev 71 3.8-30 ....................................................................................................... Rev 86 3.8-31 ..................................................................................................... ,. Rev 67
* PBAPS UNIT2                                                  X                                                      Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES PAGE REVISION LISTING 8 3.8      ELECTRICAL POWER SYSTEMS (continued) page(s}    '3.8-32 ....................................................................................................... Rev 86 3,8-33 ....................................................................................................... Rev 86
                                  '3'.8-34 ...., ................................... ,....... ,., ............................. :...................... Rev 86 3.8-35, ............,.......................................................................,........-........ Rev 117 3.8-36 ................................................: ...................................................... Rev 86 3.8-37 ....................................................................................................... Rev 71 3.8-38 ....................................................................... :............................... Rev 86
:t8-39 ................................................ ,................ ,...........*..*..............*.*.*... Rev ,95 3.8-40' ........................................................,............................................ Rev 146 3.8-42 ................................ ,................ ,..... ,.. , .......................................... Rev 146 3.8-43 ..................................................................................................... 'Rev 145 3.8-44 ........................................ ,, ............... ,........................................... Rev 145 3.8-45 .....................................................................................................Rev 145 3.8-46 ................................ ,............................... _ ................................... Rev 145 3.8-47 ........................................................:.............................................. Rev 16 3.8-48 ..................................................................................................... Rev 10'6 3.8-49 ..................................................................................................... Rev 122 3.8-61 ..................................................................................................... Rev 138 3.8-53 ..................................................................................................... Rev 138 3.8-54 ............................................................. ,, ........................................ Rev 86
                                    '3.8-65 ................................................................................,.................... Rev 122 3.8-5& .....................................................................................................Rev 122 3.8-57 .....................................................................................................Rev 1'22 3.8-59 ........................................... ,......................................................... Rev 150 3.8-60 ..........,.........................................................................,...*......*..... Rev 150 3:8-60a .................. ,........*......... ,, .... ,....................................................... Rev 160 3.8'-62, .*, ........................................................,........................................:Rev, ,154 3.8-62a .*.......,..*....*......... ,........**. ,........................................................... Rev 153"
- - - - ~ ~- --- -~~- ----------z:-1r..s21>: ..............................................................::::-:-............................... ~rf53 -
3.8-63 ..*....... ,. ........................................... - ............................................ Rev 154 3.8-63a .............................,-..................................................................."Rev 1,63 3.8-63b ............................................. , ..................................................... Rev 153 3.8-64 .............................,.......................... ,............................................ Rev 163 3.8--66 ..................................................................................................... Rev 155 3.~6 ..................................................................................................... Rev 160 3.8-67 ..... ,............................................................................................... Rev '150 3.8-68 ..............................................................,...................................... Rev 150 3.8-69 .. - *... ,, ........ ,., ................................................................................ Rev 160 3.8-70 ...............................................................,..................................... Rev '150 3.8-71 ............................. ,., ......... ,........................................................... Rev 160' 3.8-72 ............................................................................................, ........ Rev 145, 3.8-73 .................................., .................................................................. Rev 146 3.8-74 ...... , ..... ,........................................................................................ Rev 150 3.8-75 ...............................................,......................... ,........................... Rev 150 3.8-76a ..................... , ................... ,................. , .* : .................................... Rev 160 3.~76 ..................................................................................................,.. Rev 150 3.8-TT .........................................................., .......................................... Rev 150 3.8-TTa .................. ,............................................................................,... Rev 160 3.8-78 ............................... ,...... ,..*. ,........ ,....................................... , ........ Rev 160 3.8-78a ..................... ,............................................................................. Rev 150 3.B-78b ................................................................................................... Rev 150 3.8-78c ................. ,..........................., ..................................................... Rev 150
* PBAPS UNIT2                                                        xi                                                        Revision No , 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECIFICATIONS BASES
                        '          PAGE REVISION LISTING
* 83.8  ELECTRICAL POWER SYSTEMS (continued) pages(a)      3.8-19 ..................................................................................................... Rev 155 3.8-80 .............................................*....................................................... Rev 150 3.8-81 ............................................ ,..*.........................................*........... Rev 150 3.8-82 ..................................................................................................... Rev 150 3.8-85 ..................................................................................................... Rev 150 3.8-SS *****************************-************************************************************************ Rev 85 3.8-90 ..................*.............._*.* ,...*....... ,.........* ,........................................... Rev 85 3.8-91 ....................................................................................................... Rev 85 3,8-92,, .......................*...*......*........*.......... :............................................... Rev 86 3.8-94 ..................................................................................................... Rev 145 3.8-95 ................................*...............................*...*......*........*...*.... ,., ..... Rev 145 3.8-96 ........... ,......................................................................................... Rev 145 3.8-97 ..................................................................................................... Rev 145 8 3.9  REFUELING OPERATIONS 3,9-1 .................. , ........*............................................................................. Rev 29 3.9-3 ....................... :................................................................................. Rev 29 3.9-4 ......................................................................................................... Rev 86 3.9-7 ...*.......*....... ,..................................................................................... Rev :86 3.9-8 ......................................................................................................... Rev 24 3.9-9 ..................................................................................................*...... Rev 86 3.9-10 ....................................................................................................... Rev 24 3.9-14 ....................................................................................................... Rev 24 3.9-16 .. ,............................................................................................ , .... ,.. Rev 86 3.9-1'7 ., .................... , ........*. , ... ,.................... - ..................................*........ Rev 75
          - ---- - ---3.9--19-.......................................................................................... ,............ ReV- ------ -- -
3.9-21 ..................................................................................................... Rev 126 3.9-23 ...................................................... ~**** .. **-'-****** .. **-****** ......_....... , ...... Rev 126 3:9-23a ***************************************************-**********************************************Rev 1'27 3.9-23b .................................................................. ,......*............**.*........* Rev 126 3.9-25 ..*......................... , ........................................................................ Rev 126 3.9-27 ..................................................................................................... Rev 126 3.9-28 ............................................................... ,..............*..............* ,...... Rev 127 3.9-29 .... ,................................................................................................ Rev 126 B 3.10  SPECIAL OPERATIONS
        ,page(s) - 3.,10-1 ............................................ ,........................................................ Rev 129 3.10-2' ................*...*............... ,................................................................ Rev 129
                      '3.10-2a, ........................................................................................_........... Rev 145 3.10-3 ..................................................................................................... Rev 129 3.1,0-4 ..................................................................................................... Rev 129 3.,1,0-5 ....................................................................................................... Rev 24 3.10-8 ................................................ ,, ..... ,.. ,. ......................................... ,. Rev '86 3.1,0-9 ***********i*******************************************************************************************Rev 86
                      '3.10-13 ***********************~************ ................................................................ Rev 86 3.10-18 ......................... ;............................................................. ., ........*... Rev 86 3.10~22 ..................................................................................._. *.......... ,..... Rev 86 3.10-26, .................. _ ................................................................................. Rev 86
* PBAPSUNIT2                                                                                                                    Revision No. 157
 
PBAPS UNIT 2 - LICENSE NO. DPR-44 TECHNICAL SPECiFiCATIONS BASES PAGE REVISION LISJING
* B 3.10    SPECIAL OPERATIONS (continued) page(s)  3.10-30 .................................... , ....*....... , ................................................... Rev 72
                      ,3.10-31 ...........................................................*........*.... ,..*........................ Rev~
3.10-32 ....................................................... .............................................. Rev' 36 3.'10-33 ......................................................... ,.,. .*...................................... Rev 63 3',10-35 ..................................................................*...*...........................*.. Rev 86 3'.10-36 .*............... ,................*........*..*.............*.....*............*..................... Rev 86 AJI remaining pages am Rev O dated 1/18/96 .
* PBAPS UNff2                                                xiii                                                        Revision No. 157
 
TABLE OF CONTENTS
* B 2.0 B 2.1.1 B 2.1.2 B 3.0 SAFETY LIMITS CSLs) ......................................... B 2.0-1 Reactor Core SLs ................... , ................ B 2. 0-1 Reactor Coolant System (RCS) Pressure SL ..*........ B 2.0-7 LIMITil'fG COt-lDIT!ON FOR OPrRATION CLCO) APPLICABILITY ........ B 3.0-1 B 3.0        SURVEI LLANGE REQl)I REMENT ( SR) APPLICABILITY .**........... , .. B *3. 0-10 B 3.1            REACTIVITY CONTROL SYSTEMS .................*.........*..            B 3.1-1 B 3.1.1                SHUTDOWN MARGIN CS.OM) .*...........**.........**..*..        B* 3.1-J B 3.1.2                Reactivity Anoma.lies ................................        8 3.1-8 B 3.1.3                Control Rod OPERABILITY ...............................        B 3. 1-13 B 3,1.4                Control Rod Scram Times .*...........*..............*          B 3.1-22 B 3.1.5                Control Rod Scram Accumulators *........................      B 3.1-2S B 3.1.6                Roa Pattern Control .................................          B 3.1-34 B3.1.7                  Standby Liquid Control (SLC) System ..*.......*....*.          B 3.1-39 8 3.1.8                Scram Discharge Volume (SDV) Vent a.nd Drain Valves ..        B 3.1-48 B 3.2            POWER DISTRIBUTION LIMITS ............... ,. ...............        B 3.2-1 B 3 .. 2 .1            AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) ......*.......*....*........*............*        B 3.2-1 B 3.2.2                MINIMUM CRHICAL POWER RATIO (MCPR) ....*.*...*...*..          B 3.2-6 B 3.2.3                LINEAR HEAT GENEf<ATION RATE (LHGR) .................          B 3.2-11 B 3.3            INSTRUMENTATION ..... , ....................... , ...........        B  3.3-1 B 3.J.1.1        Reactor Protection System (RPS) Instrumentation .**......            B  3.3~1
* B 3,3.1.2        Wide Range Neutron Monitor CWRNM) Instrumentation .......            B  3.3-36
-- - ~ -~--:~.c ;-"'l- -c-011*-rro*1-iroa-sr-ocrrnstn.1rnenfafi on .................--::*:-.... B  3 .. 3--45 ~
B 3.3.2.2        Feeawater and Main Turbine Higr Water Level Trip Instrumentation ...*...............**...............      B 3 .. 3-58 B 3.3.3.1        Post Accident Monitoring (PAM) Instrumentation ..........            B 3.3-65 B 3.3.3.2        Remote Shutdown System ..*......*.*.....*.....................      B 3.3-76 B 3.3.4.1        Anticipated Transient Without Scram Recirculation Pump Trip (ATW$-RPT) Instrumentation ..............        B 3.3-83 B 3.3.4.2        End of Cycle Recirculation Pump Trip (EOC-R-f'lT) Instrumentation . .
* B 3.3-91a thru      B 3.3-9lj B 3.3.5.l        Emergency Core Cooling System (ECCS) lnstrumentat i ort *....**..*...*.....*..............      B 3. 3-92 B 3.3.5.2        Reactor Core Isolation Cooling (RCIC) System Instrumentation ......**.............*.........*...        B 3.3-130 B 3.3.5.3        Not  Used  .......*........*........*.........*......*......        B-3.3~140a B* 3. 3. 5 .4    ReQ"ctor Pressure Vess.el ( RPV) Water Inventory Control Instrumentation ........................*........*.        B-3.3.140b 8' 3.3.6.1        Primary Containment Isolation Instrumentation ..........*            8 3.3-141 8 3.3,6.2        Secondary Co~tainment Isolation Instrumentation, .*......            B 3.3-169 B 3.3.7.1        Main Control Room Emergency Ventilation (MCREV)
System Instrumei::itation .................... ,. ..... B 3.3-180 B 3.3.8.1        Loss of Power (LOP) Instrumehtatfon ...*........*........            B 3.3-187 B 3.3.8.2        Reactor Protection System (RPS) Electric Power Monitoring ..*...............*..*..*....*........*          B 3.3-19*9 (continued)
PBAPS UNIT 2                                                            Revision No. 145
 
TABLE dF CONTENTS (.continued)
* B 3.4 B
B B
3.4.1 3.4.2 3.4.3 REACTOR COOLANT SYSTEM (RCS) ........................... ,
Recirculation Loops Operating **..*......*.......*...
Jt Pumps ...*.*......**.. *.......**....................
Safety Relief Valves (SRVs) and Safety Valves (SVs).
B 3.4-1 B 3.4-1 B 3.4-11 B 3.4-15 B 3,4.4                  RCS Operational LEAKAGE'. *.*..*...*.....* *......*...*...                                          B 3.. 4-19 B 3.4.5                  RCS leakage Detection Instrumentation ..........**...                                                B 3.4-24 B 3.4.6                  RCS Specific Activity ............*....*....*..*.....                                                B 3.4-29 B 3.A-.Y                Residual Heat Removal {RHR) Shutd6wn Cooling System-Hot Shutdown .............*........ , .** , .*                                          B 3.4-33 B 3.4.8                  Residual Heat Removal CRHR) Shutdown Cooling System-Cold Shutdown .. , .....**.....*.*.....*....                                            B 3.4-38 B 3.4.9                  RCS Pressure and Temperature (P/T) Limits *..........                                                B 3.4-43
          '8 3.4.10                  Reactor Steam Dome Pressure *........................                                              B 3.4-52 B 3,5              EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL (WIC), AND REACTOR CORE ISOLATION COOLING (RC!{:) SYSTEM ..*........*................ , .......                                              B  3.5-1 B 3. 5.. 1                ECCS .*..................*..*..*.**.. , ...*.......*...                                            B  3.5-l B 3.5.2                  Deleted .......... : *...............***.......*.*..*..                                            B  3.S-18 B 3.5.3                  RCJC System ........... , ..*........*...*..*............                                          B  ~ *.5-24 B 3.5.4                  RPV Water Irrventory Control .........................                                              B  1. 5-25 B 3.6              CONTAINMENT SYSTEMS .................. , ..................                                                B 3.6-1 B 3.6 ..1.1        Primary Containment .....................................                                                  B 3.6~1 B 3,6.1.2          Primary Containment AiT Lock ............................                                                  B 3.6-6 B 3.6.1.3          Primary Containment Isolation Valves (PCIVs) .........*.*                                                  B 3.6-14
. - ~ - - 8 3 ..6-.1....4- --D-r-y..we-1-1--Ai-r-:f.empe--r-at-tl-r-- ..-** ;--;--.--;-;-..--.-.---.--.~ ..........*....                S--3. 6 - ~ - - -
B 3.6.1.5          Reactor Building-to-Suppression Chamber Vacuum Bre a ke rs . . * . . . . . . . * . . . .. . . . . . . . . . . . . , . . . . .. . . . . . . . . B  3 . 6 *- 34 B 3.6.1.6          Suppression Chamber-to-Orywell Vacuum Breakers ..........                                                  B  3.6-42 B 3.6.2.1          Suppression Pool Average Temperature.:, .....**........*..                                                B  3.6-48 B 3.6.2.2          Suppression Pool Water Level .............*..*..........*                                                  B  3.6-63 B 3.6.2.3          Residual Heat Removal CRHR) Suppression Pool Cooling ...........................................                                            B 3.. 6-56 B 3.6.2.4          Residt1al    Heat RefTloval (RHR) Supp,ressfon Pool Spray ..*...                                          13 3.6-60 B 3,fi.2.5        Residual      Heat Removal (RHR) Drywell Spray **.*...... , ....                                          B 3.6-63a B 3.6.3.l          Deleted    ....*.....*.*.          , ..*...*..*........***...... : .... , .                              B 3.6-64 B 3.6.3 . .2      Prima~y Containment Oxygen Concentration ...**...***.***.                                                  B 3.6-70 6 3.6.4 .. 1      Secondary Containment ..*..*........* , ..............**...                                                B 3.6-73 B 3.6.4.2          Secondary Containment Isolation Valves (SCIVs) ...........                                                  B 3.6-78 B 3.6.4.3          Standby Gas Treatment ( SGT) System ..*....*.......*.*.....                                                B J.6-85 B '3. 7            PLAN'f SY.STEMS ..*...........*...............*.............                                                B 3. 7-1 B 3.7.1                    High Pressure Service Water ( HPSW) System ...........                                              B 3. 7-1 B 3.7.2                    Emergency Service Water (ESW) System and Normal H.eat Sink ...........*.*......*. , .......*.*. , *..*                                          B 3.7-6 B 3.7.3                    Emergency Heat Sink .................................                                                B 3.7-11 B 3.7.4                    Main Control Room Emergency Ventilation CMCREV)
System .............*.......*.. , **......*....*.....                                            B 3. 7~15
  *      *PBAPS UNIT 2 Main Condenser Offgas ..*......*..*...............*..
ii                                        Revis1on No. 145 B 3.7-22
 
TABLE OF CONTENTS (tantinued)
B 3. 7        PLANT SYSTEMS (continued)
: 13. 3.7.6          Main Turbine Bypass Sntem .....*.................... B 3. 7-25 B 3.7.7            Spent Fuel Storage Pool W-0ter Leve1 .................. B 3. 7-29 B 3.S        ELECTRICAL POWER SYSTEMS ...*.....................*........                              B 3. 8- 1 B 3.8.1            AC Sources-Operating ...............................                                B 3.8-1 B  :3-. 8. 2      AC Sources-Shutdown ..................................                              B 3.8-40 B  3.8.3          Diesel Fuel Oil, Lube Oil, and Starting Air .........                              B 3.8-48 B  3.8.4          DG S,ources-Operating ...............................                              B 3.8-58 B  3 .8 .. 5      DC Sources-Shutdown *..... , ..........................                            B 3.B"72 B  3:8. 6        Battery Parar[lehrs......*........................ , .*.                            B 3. 8- 77 B  3.8.7          Distribution Systems-Operating .*... ; ..............*                              B 3.8-83 B  3.8.8          Distribution Systems-Shutdown ......................                                B 3.8-94 B 3.9        REFUELING OPERATIONS ...............*..............**....                                B 3.9~1 B 3.9.1            Refueling Equipment Interlocks ......*................                              B 3.9-1 B J.9.2            Refu!?l Positi0,n One-Rod-Out Interlock ...............                            B 3.9-5 B 3.9.3            Control Rod Position ..................... ' ... ; .......                          B 3.9-8 B 3.9.4            Control Rod Po s i ti on Ind i cat i on . . . .. .. . . . . . . . . . * . . . * . . B 3 . 9 - 10 B 3.9.5            Control Rod OPERABILITY-Refueling ..............*...                                B 3.9-14 B 3.9.6            Reactor Pressure Vessel (RPV) Water Level ........*.....                            B 3.9-17 8 3.9.7            Residual Heat Removal (RHR)-High Water Level .......                                B 3.9-20 8 3.9.8            'Resi<:lual Heat Removal (RHR)-Low Water Level .........                            B 3.9-24
* B 3.10 B 3.10.1
    -~~-
B 3.10.3 B 3.10.4 8 3 .10. 5 SPECIAL OPERATTONS ...................................... B 3.10-1 Inservit:e Leak ar:id Hydrostatic Testing Operation .... B 3 .. 10-I
                  -K"e"rrtorr1mieSwTFcF17meYlocR I esti ng ..... -........ -.-: B -:r:-t----s------
Si ngl e C{)ntrol Rod Withdrawal-HDt Shutdown ......... B 3.10,10 Single Control Rod Withdrawal-Cold Shutdown ........ B 3.10-14 Single Cor:itrol Rod Drive .<CRD)
Removal.,_ Refueling ... , *......... *...................B 3 .10-19 B 3.10.6          Multiple Control Rod l{ithdrawal-Refueling ........... B 3.10-24 B 3.10.7          Control Rod Testing-Operating ............. , , ..... , . B 3.10,27 B 3.10 .. 8      SHUTElOWN MARGIN (SOM) Test-Refueling ............... B 3.10-31
* PBAPS UNIT 2                                iii                                          Revision No. 150
 
Recirculation Loops Operating B 3.4.1 B 3.4  REACTOR COOLANT SYSTEM (RCS)
B 3.4.1  Recirculation Loops Operating BASES BACKGROUND        The Reactor Coolant Re~irculat1on System is designed to provide a forced coolant flow through the core to remove heat from the fuel. The forced coolant flow removes more heat tram the fuel than would be possible w*tth just natural circulation. The forced flow, therefore, allows operation at .significantly higher power than would otherwise be possible. The recircu1ation system also controls reactivity over a wide span of reactor power by varying the recircu1at1on f1ow rate to control the void content of the moderator. The Reactor Coolant Recirculation System consists of two rec1rt:ulat1on pump loop.s external to the reactor vessel. These loops provide the piping path for the driving flow of water to the reactor vessel jet pumps. Each external loop contains one variable speed motor driven recirculatio~ pump, an adjustable speed drive CASO) to control pump speed and associated piping, Jet pumps, valves, and instrumentation. The recirculation loops are part of the reactor coolant pressure boundary and are located 1ns1de the drywe11 structure. The jet pumps are reactor vessel internals.
The rec1r-culated coolant consists of saturated water from the stea~ separators and dryers that has been subcooJed by incoming fe~dwater. This water passes down the annulus between the reactor vessel wall and the care shroud. A portion of the coolant flows from the vessel, through the two external recirculation loops, and becomes the ariving ffow for the jet pumps. Each of tne two external recirculation loops: discharges high pressure flow 1nto an external manifold, from which individual recirculation inlet lines are routed to the jet pump rise*rs within the reactor vessel. The remaining portion of the coolant mixture in the annulus becomes the suction flow for the jet pumps. T~is flow enters the jet pump at suction tnlets and is accelerated by the dr1 v111g fl ow. The drive fl ow and suction flow are mixed in the jet pump throat iectfon. The total fl ow then passes through the jet pump d1ffusar section into the area below the core (lower plenum), gaining sufficient head in the process to drive the required flow upward through the core. The subcooled water enters the bottom of the fuel channels and contacts the fuel cladding, where heat is transferred to the coolant. As it rises, the coolant (continued}
* PBAPS UNIT 2                          B 3.4-1                    Revision No. 137
 
Recirculation Loops Operating B 3.4.1 8ASES BACKGROUND        begins to boil, creating steam voids within the ft:tel channel
( continued)  that continue until the coolant exits the. core. BecaJ1s.e of reduced moderation, the st~am voiding introduces negative reactivity that must be compensated for to maintain or to increase reactor power. The recirculation flow control allows operators to increase recirculation flow and sweep some of the voids from the fuel channel, overcoming the negative reactivtty vo1d* effect: Thus, the rea~on for having variable recirculation flow is to compensate for reactivity effects of boiling over a wide range Of power generation (i.e., 65 to 100% of RTP) without having to move control rods and disturb desirable flux patterns.
Each recirculation loop is manually started from the control room. The ASD provides regulation of ind1v1daal recirculation loop drive flo~s. The flow in each loop is manually controlled.
APPLICABLE        The operation of the Reactor Coolant Recircu~ation System 1s SAFETY ANALYSES    an 1nitfal condition assumed in the design basis los*s of cool ant acc1 dent. ( LOCA) (Ref. 1). During a LOCA caused by a recirculation loop pipe break, the intact loop is assumed to provide coolant*flow during the first fe~ seconds of the accident. The init1al core flow decrease is rapid because
__ the ,tec,ircuJ a.tJ QO. _p.ump_ 1n_tne _b r_oru_J..OQ.1:u;e!l_s~-- to R.1!11JR-.- __ _
reactor coolant to the vessel almost immediately. The pump in the intact loop coasts down relatively slowly. This pump coastdown governs the core fl ow response for the next several seconds until the jet pump suction is uncGivered.
the analyses assume that both loops are operating at the same f,ow prior to the accident. However, the LOCA analysis was rev1 ewed for the case 'W1 th a fl ow, mismatch between the two loops, with the pipe break assumed to be in the loop with the higher flow. While the flow coastdown and core response are potentially more severe in this assumed case (since the intact loop starts at a lower flow rate and the core response is the same as if both loops were operating at a lower flow rate), a small mismatch has been derermined to be acceptable based on engineering judgement. The recirculation system 1s also assumed to have sufficient flow coastdown characteristics to maintain_fuel thermal margins during abnormal operational transients, which are analyzed in Chapter 14 of the UFSAR.
Ccontj nued >
PBAPS UNIT 2                              B 3.4-2                            Revision No. 137
 
Recirculation Loops Operating B 3.4.1 BASES APPLICABLE      Plant specific LOCA and average power range monitor/rod SAFETY ANALYSES  block monitor rechni cal Specif'i cation/maxi mum ,extended load (continued)  line limit analyses have been performed assuming only one operating recirculation loop. These analyses demonstrate that, in the event of a LOCA caused by a pipe break in the operating reci rcul at ion loop, the Erne rgency Core Cool i ng System response will provide a,dequate core cooling CRefs. 2, 3, 4, 7 and 8). The Maximum Extended load Line Limit Analysis Plus (MELLLA+) op~rating domain has not been
                            .analyzed for single recirculation loop operation.
Therefore, single l9op opetation is prohibited in the MELLLA+ operating domain (Ref. 9).
The transient analyses 0f Chapter 14 of the UFSAR have also been performed for single re,ci rcul ati on loop operation (Ref. 5) and demonstrate sufficient fl.ow t'Oastdown characteristics to maintain fuel thermal margins during the abnormal operational transients analyzed provided the MCPR requirements are modified. During single recirculation foop operation, modification to th.e Reactor Protection System (RPS) average power range monitor (APRM) instrument setpoints is al so required to account for the d1 fferent rel ati onshi ps between reci. rcul ati on drive. fl ow and reactor
* core flow. The MCPR limits and APLHGR limits (power-
------~-- -------~~~----- -11~m1mrr AYL11GR----mul ti-p-l i e~A--P-FA1:~--;--ana--n ow=c!epencfer'G-r---- --~---
APLHGR multipliers, MAPFACt) for single loop operation are specified in- the COLR. The APRM Simulated Thermal Power-High Allowable Yalue is in LCD 3.3.1.1, "Reactor rrotection System (RPS) Instrumentation."
* PBAPS UNIT 2                        B 3.4-3                        R_e vi s i on No . 12 3
 
Recirculation Loops Operating B 3.4.1
* BASES APPLICABLE SAFETY ANALYSES (continued)
Recirculation loops operating satisfies Criterion 2 of the NRC Policy Statement.
LCD            Two recirculation loops are normally required to be in operation with their flows matched with{n the limits specified in SR 3.4.1.1 ta ensure that during.a LOCA caused by a break of the piping of one recirculation loop the
* PBAPS UN IT 2                    B 3.4-4                    Revision No. 50
 
Recirculation Loops Operating B 3.. 4. 1 BASES LCO (contint1ed).        assumptions of the LOCA analysis are ~atisfied.
Al t e rn at i vel y
* wit h on Ty on e r e c i r cu l a ti on l ob p i n operation, modifications to the required APlHGR limits (power- and flow-dependent APLHGR multipliers. MAPFACp and MAPFACt, respect1Vely o,f LCD 3.2.1, "AVERAGE PLANAR LINEAR HEAT GEN.ERATION RATE (APLHGR)"), MCPRlirnits (LCD 3.2.2, *
                        "MINIMUM CRl!ICAL POWER RATIO (MCPR)") and APRM Simulated Thermal Power-High Allowable Value (LCO 3.3.1,1) must be applied to allow continued operation consistent with the assumptions of Reference 5. $,i n.gl e loop operation is prohibited in the MELLLA+ operating domain per Reference 9.
The LCO is modified by a Note which allows up to 12 hours before having to put in effect the required modifications to required limits after a change in the reactor operaUng conditions from two recirculation loops operating to single recirculati-On loop vperation. If the required limits are not in compliance with the applicable requirements at the en~ of this period, the associated equipment must be
                        ,declared inoperab1e or the limits "not satisfied," and the ACTIONS required by non conformance with the appl 'i cable specifications implemented. This time is provided due to the need to stablli.ze aperation with one recirculation loop,
          -  - - - --- 7ITC1lltl"i17ythe7Yrocl!T.fi"cfr-nejYsffec'e"$sa-ry'co r lITll f now in                .
the operating loop, and the complexity and detail required to fully implement and confirm the required limit modi fi cati on.s ..
APPL1CABI LITY        In MODE~ 1 and 2, requirements for operation of the Reactor Coolant Recirculation System are necessary since there is considerable energy in the reactor core and the limiting design basi5 transients and accidents are assumed to occur.
In MODES 3, 4. and 5, the consequences of an accident are reduced and the coastd0wn characteristics of the recirculation loops are not important.
(continued)
* PBAPS UNIT 2                                    B 3.4-5                                Revision No. 123
 
Recirculation Loops Operating B 3.4.1 *
* BASES THIS PAGE L~FT BLANK INTENTIONALLY (The conte.nts of this, page have been deleted)
* PBAPS UN IT 2                    B 3.4-6                      Revision No. 50
 
Recirculation Loops Operating
                                                                                              . B 3,4 .1 BASES  ( continued)
ACTIONS W1th the requirements of the LCD not met, the recirculation 1oops must be restored to opera ti on with matched flows within 24 hours. A recirculation loop is considered not in operation when the pump in that loop is idle or when the mismatch between total jet pump flows of the two loops is greater than required 1 i mits. ihe 1 oop with the lower fl ow must be considered not in operation. Should a LOCA oGcur with one recirculation loop not in operation, the tore fiow coastdown and resultant core response may not be bounded by the LOCA analyses. Therefore, only a limited time is allowed to restore the inoperable loop to operating status.
Alternatively, if the single loop requirements of the LCO are applied to operating limits and RPS setpoints, operation with only one recirculation loop would satisfy the requirements of the LCO and the initial conditions of the accident sequence. Note that sing1e loop operation is prohibited in the MELLLA+ operating domain per Reference 9.
The 24 hour Completion T*i me is based on the low probability of an accident occurring during this time pert,od., on a reasonable time to complete the Required Action, and on
- -- -- - -- - - ~ - - * ** -- * *---n*e-q  enccorerrmniTor7ng *byofferaTorT-al rowing aorupt ___ - -
* changes in t0re flow condition*s to be qu'ickly detected.
This Req1:Ji red Action qoe*s not require tri pp1 ng the.
recirculation pump in the lowest flow loop when the mismatch between total jet pump flows of the two loops is greater than the requj red limits. However, in case.s where 1arge flow mismatches occur, low f1ow or reverse flow can occur in the low flow loop jet pumps, causing vibration of the jet pumps.. If zero or reverse fl ow is dete.cted, the condi t1 on should be alleviated by changing pump speeds to re-establish forward flow or by tripping the pump .
* PBAPS UNIT 2                              B 3.4-7                      Revision No. 123
 
Recirculation Loops Opera~ing B 3.4.1 BASE:S ACTIONS            .B..i..l (continued}
The MELLLA+ operating domain is not analyzed for single reci rcul ati on 1oop operation. Therefore, single, loop operation is prohibited 1n the MELLLA+ operati~g domain (Ref. 9). Action shall be, taken to i.mmediately exit the MELLLA+ domain in order to return to operation at an analyzed con di ti on, However, it is expected that pl ant design limitations will preclude operation in the MHLLA+
domain with a single re.circulation loop.
Ll With no recirculatton loops in operation or the Required Action and associated Completton Time of Condition A or B not met, the plant must be brought to a MODE in which the lCO dos not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours. In this condition, the recifculation loops are not required to be operating because of the reduced severity of DBAs and minim~l I
dependence on the recirculation loop coastdown characteristics. The allowed Completion time of 12 hours is reasonable 1 based on operating experience, to reach MODE 3
              --f-rc,m-fu-l l--.&#xb5;ower-condlt1 ons--tn--an--orderly- m,rnrr-e-r-a*rrd-\ifiTMUf ________
challenging plant systems.
( continued)
PBAPS UNIT 2                            B 3.4-8                      Revts1on No. 123
 
Recirculation Loops Operating B 3.4.1 BASES  (continued)
SURVEILLANCE              SR 3-4-.1.1 R6QUIREMENTS This SR ensures the recirculation loops are within the allowable limits for mismatch. At low c0re flow (i.e.,
                                                          < 71.75 X 10 6 lbm/hr}, the MCPR requirements prov1de larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effeGt of early boiling transition during a LOCA is reduced. A larger flow mismatch can therefore be allowed when core flow is< 71.75 X 10 6 lbm/hr. The recirculation l0op jet pump flow, as used in this Surveillance, is the summation of the flows from an of the jet pumps associated with a single recirculation loop. -
The, mismatch is me.as.ured in terms of core flow. (Rated core flow is 102.5 X 10 6 lbm/hr. The first lirn'it is based on mismatch :;;, 10% of rated core fl ow When o.perati ng at < 70% of rated core fl ow. The second 1 i mi t is based on mismatch :s; 5%
of rated core flow when operating at~ 70% of rated core flow.) If the flow mismatch exceeds the specified limits, the loop with the lower flow is considered not in operation I
*----~.,........,....------. ----------- . ----, .......-
and operation in the MELL LA+ ,domain is prohibited per Reference 9. The SR is not required when both loops a re n0t in operation since the mismatch limits are meaningless
                                                          -dur-i n-g-- -single l"OOJr or-n-at ura 1- ;circul Ft ibnoperatTon :- --The -- - -
surveillance must be performed Within the specified Frequency after both loops are in operation. The surveillance Frequency is controlled under the Surveillance Frequency Control Program.
( cont i nu ed )
PBAPS UNIT 2                                                                          Revision No. 123
 
, BASES  (continued)
Recirculation Loops Operating B 3.
 
==4.1 REFERENCES==
: 1. UFSAR, Section 14.6.3.
: 2. NEDC-32163P. "PBAPS Units 2 and 3 SAFER/GESTR-LOCA LiJss-of-Coolant Accident Analysis," January 1993 .*
: 3. NEDC-32J62P, "Maxi mum t:xtended Load Line Limit and ARTS Improvement Program A*nal yses for Peach B,ottom Atomic Power Statton Unit 2 and 3," Revision 1, February 1993.
: 4. NEDC-32428P, "Peac~ Bottom Atomic Power Station Unit 2 Cycle 11 ARTS The.rma1 Lim1ts Analyses," December 1994.
: 5. NED0-24229-1, "PBAPS Units 2 and                  3 Single-Loop Operation," May 1980.
: 6. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 ahd 3, Constant Pressure Power Uprate," Revis.ion O.
: 7. G-080-VC-400, "Peach Bottom Atomic Power Station Units 2 & 3 GNF'2 ECCS-LOCA Evaluation," GE Hitachi Nuclear I                - -- --8 ___
Energy, 0000-0100-8531-Rl, March 2011.
                              -G" 080.o---VC~ 2.7-2-,- _!'Peach -8 ot-tom--A tomi c~-P-Gwe r'--Sta t i--on - EGC S=- -
LOCA Evaluati.on for GE14," General Electric Company,
                                                                                                                      - - - ~--
GENE-Jll-03716-09-02P, July 2000.
: 9. NEDC-33006P-A,. "Maximum Extended Lo~d Line Limit Analysis Plus Licensing Topical Report 1 " Revision 3, June 2009.
PBAPS UN IT 2
* B 3.4-10                                Revision No. 123
 
Jet PUtnps B 3.4.2
* B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.2 Jet Pumps BASES BACKGROUND            The Reactor Coolant Recirculation System is described in the Background section of the Bases for LCO 3.4.1, ARecirculation Loops Operat1ng,A whiC~ discusses the operati,ng characteristics of the system and how these characteristics affect the Design Basis Accident (OBA) analyses.
* The jet. pumps are reactor vessel. internals ahd in conjuncti"On with the Reacto~ Coolant Reci.rculation System are designed to provide forced circulation through the core to remove heat fl"Olll the fuel. The jet pumps are located in the annular region between the core shroud and the vessel
* inner wall. Because the jet pump suction elevation is at two-thirds core height, the vessel can be reflooded and
* coolant level maintained at two-thirds core heigh.t even with the complete break of the recirculation loop pipe that is located below the jet pump suction elevation.
Each reactor coolant recirculation loop contains ten jet pumps. Recirculated coolant passes down the annulus between
                  , . -* --the -Feae.tor*-vesse 1--waH -~nd-t-he ,core -shroud. --A---porti on-of-- - - -
the coo1a.nt flows froa the vesse 1 , through the two externa1 recirculation loops, and becomes the driving *flow for the jet pumps. Each of the two external recitculatfon loops discharges high pressure flow into an external manifold from which individual reci.rcul at ion inlet lines are routed to the jet pump risers within the reactor vessel. The remaining
                            .portion of the coolant mixture in the annulus becomes the suction fl ow for the jet pwops. This flow enters the jet pump at suction inlets and is accelerated by the dri\fe flow.
The drive flow and suction flow are mixed in the jet pump throat section. The total flow then passes through the jet pump diffuse,r section into the area below the core (lower plf!num), gaining sufficient head in the process to drive the required flow upward through the core.
APPLICABLE            Jet pwap OPERABILITY is an implicit assumption in the design SAFETY ANALYSES      basis loss of coolant accident (LOCA) analysiS evaluated in Reference 1.
{continued)
*
* PBAPS UNIT 2                            B 3.4-11                          Revision No. O
 
Jet Pumps B' 3.4.2 BASES APPUCABI..E    The capability of reflooding the core to two-thirds core SAFETY ANALYSES he:fght is dependent upon the structural integrity of the jet (continued)  pumps. If the structural system, including the beam holding a jet pump in place, fails, jet pump dtsplacement and perfotlllance degradation could occur, resulting in an increased fl ow area through the jet pump and a lower core.
flooding elevation. This could adve~sely affect the water level i.n the core during the reflood pha*se of a LOCA as well as the assumed blowdown flow during a LOCA.
Jet pumps satisfy Criterioh 2 of the NRC Policy Statement.
LCO            The structural failure of any of the jet pumps could cause significant degradation in the ability of the jet pumps to allow reflooding to two-thirds core he.ight during a LOCA.
OPERABILITY of all jet PlDIIPS is required to ensure that operation. of the Reactor Coolant Recirculation System will be consistent with the assumpticms used in the licensing basis analysis (Ref. 1).
APPLICABILITY  In MODES 1 and 2, the jet pumps are required to be OPERABLE since there is a large amount of energy in the reactot core
      '                      and since the limiting DBAs are assumed to occur in these
- ~----'-- - - ~ - - -- ~--MOD&S-.--+his--1-s-GOn-sls-tent-w.:t-th-t--he--requ-irements-for-operation of the Reactor Coolant Recirculation System
                                                                                            ~ ---~- -
(LCO 3.4.1).
In MODES 3, 4, and 5, the Reactor Coolant Recirculation System is not required to be in operation, and when not in operation, sufficient flow is not available. to evaluate jet pump OPERABILITY.
ACTIONS        AJ.
An inoperable jet pump can increase the blowdown area and reduce the capability of reflooding* during a design basis LOCA. If one or mote of the jet pumps are inopera.b1e, the
                              ~lant must be brought to a MOOE in which the LCO does not apply. To achieve this status, the.plijnt must be brought to HOOE 3 within 12 hours. The Cm,pletiori':-Tiane of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.
(continued)
PBAPS UNIT 2                      B 3.4-12                          Revision No .. O
 
Jet Pumps B 3.A.2
* BASES (continued)
SURVEILLANCE REQUIREMENTS SR 3,4.2rl This SR is designed to det~ct significant degradation in jet pump perfonnance that precedes jet pllll1J) failure (Ref. 2).
This SR is required to be performed only when the loop has forced reci rcul at ion fl ow si nee survei 11 ance checks
* and measurements can only be performed during jet pump operation. The jet pump failure of concern is- a complete inixer displacement due to jet pump beam failure. .Jet PlJIIJP pluggi.ng is also of concern since it adds fl&deg;'1f resistance to the recirculation loop. Significant degradation is _
indicated if the specified criteria confirm unacceptable deviations from established patterns or relationships. The allowable devtations from the establi.shed patterns have been developed based on the variations experienced at plants during nonnal operation and with jet pump assembly fafl ures (Refs. 2 and 3). Each recirculation loop must satisfy one Qf the performance criteria provided. Since refueling activities (fuel assembly replacement or shuffle, as well as any modifications to fuel support orifice size or core plate bypass flow) can affect the felationshtp between core flow, jet pump flow, and recirculation loop flow, these relationships may need to be re-established each cycle.
Similarly, initia1 entry into extended single loop, operation may also require establishment of these relattonsMps.
              -* -- ---Ouri ng---the~ i niti a-1----weeks- of-operation- under*"such --cond-it*i ons-f --- ---
while baselining new *established patterns.,* engineering judgement of the daily surveillance results is used to detect significant abnormalities which could indicate a jet pllfilp failure.
The recirculation pump speed operating characteristics (pump flow and loop flow versus pl.Dllj) speed) are determined by the flow resistance from the loop suction through 'the jet pump nozzles. A change in the relationship indicates a plug, fl ow restriction, loss in pump, hydraulic performance, leakage, or new flow path between the recirculation pump discharge and jet pump nozzle. For this criterion, the pump flow and loop. flow versus pump speed relationship must be verified.
Individual jet pumps in a recirculation loop nonually do not have the same flow. The unequal flow is due to the drive flow mani'fold, which does not distribute flow equally to all risers. The flow (or jet pump diffuser to lower plenum differential pressure) pattern or relationship of one jet
{continued)
* PBAPS UNIT 2                                ll 3.4-13
* Revision No. o
 
Jet Pamps B 3.4.2 BASES SURVEILLANCE      SR  3.4,2,1 (continued)
REQUIREMENTS pump to the loop average is repeatable. Arr appreciable change in t~is relationship is an indication that increased (or reduced) resistance has occurred in one of the jet pumps., This may be indicated by an increase in the relative flow for a jet pump that has experienced beam cracks.
The deviations from normal are considered indicative of a potential. problem in the recirculation* drive flow or jet pump system (Ref. 2). Normal flow ranges and established jet pump flow and differential pressure patterns are established by plotting historical data as discussed in Reference 2.
The Surveillance Frequency is controlled .under the Surveillance Frequency Control Program.
This SR is modified by two Notes. Note 1 allows this Surveillance not to be performed until 4 hours after the associated recirculation loop is in operation, since these checks can only be performed during jet pump operation. The 4 hours is an acceptable time to establish conditions
* ~----      ~
appropriate for data collection and evaluation.
              ~-~--Note-2-a~.:Jows-th-i s~SR--not-to--be- perform~d7lnti1 --z-~ hours after THERMAL POWER exceeds 22.6% of RTP. During low flow conditions. jet pump noise approaches the threshold response of the associated fl ow instrumentation and precl ucles the
                                                                                        --~-----
collection of repeatable and meani.ngful data. The 24 hours is an acceptable time to establish conditions appropriate to perform this SR.
REFERENCES        1. UFSAR, Section 14.6.3.
: 2. GE Service Information Letter No. 330, "'Jet Pump Beam Cracks," June 9, 1980.
: 3. NUREG/CR~3052, "<;loseout of IE Bulletin 80-07:        BWR Jet Pump Assembly Fail u,re," November 1984.
: 4. NEDC-33873P, "Safety Analysis Report for Peach Bottom Atomi.c Power Station, Uni'ts 2 and 3, Thermal Power Optimization,'' Revision O*
* PBAPS UNIT 2                        B 3.4-14                      Revision No. 143
 
tlet Pumps 8 3.4.2
* BASES SURVEILLANCE        SR    3.4,2,l                    (con'tinued)
REQUIREMENTS pump to the loop average is repeatable. An appreciable change in this relationship is an indication th,at increased (or reduced) resistance has occurred in one of the jet pumps. This may be indicated by an increase in the relative flow for a jet pump that has experfenced beam cracks.
The deviations, from normal are considered indicative of a potential rroblem in the recirculation drive flow or jet pump system (Ref. 2). Normal flow ranges and established jet pump flow and differential pressure patterns are established by plotting historical data as discussed in Reference 2.
The Surveillance Frequency is controlled under the Surveillance Frequency Control P~ogram.
This SR is modified by two Notes. Note 1 allows this Surveillance not to be performed until 4 hours after the associated recirculation loop is in operation. since these checks can only be performed during jet pump operation. The 4 hours is an acceptable time to establish ~ondftions appropriate for data collection and evaluation.
                    -----~~- --...........- --- ........
Note 2 allows this SR not to 'be performed until 24 hours after THERMAL POWER exceeds 23% of RTP. During low flow conditions, jet pump noise approaches the threshold response of the associated flow instrumentation and precludes the collection of repeatable and meaningful data. The 24 hours i~ an acceptable time to establish conditions appropriate to perform this SR.
REFERENCES          1.      UFSAR. Section 14.6.3.
: 2.      G[ Service Information Letter No. 3'30, "Jet Pump Beam
* Cracks f'' June 9, 1980.
: 3.      NUREG/CR-3052, "Closeout of IE Bulletin 80-07:    BWR Jet Pump Assembly Failurej~ November 1984 .
* PBAPS UN l:T 2                                            B 3.4-14  Revision No. 114
 
SRVs and SVs B 3.4.3
* B 3 .4    REACTOR COOLANT S'l'.STEM (RCS)
B 3.4.3    Safety Relief Valves (SRVs) and Safety Valves (SVs)
BASES BACKGROUND            The ASME Code requires the reactQr pressure vessel be protected from overpressure during upset conditions by self-actuated safety valves. As p~rt of the n~clear pressure relief system, the .size. and number of SRVS and $Vs are selected such that peak pressure in the nuclear system will not exceed the ASME Code limits for the reactor coolant pressure boundary (RCPB).
The SRVs and SVs are located on the* main steam lines between the reactor vessel and the first isolation valve within the drywe-11 . The SRVs can actuate by either of two modes: the safety mode or the depressurization mode. In the safety mode, the pilot disc o,pens when steam pressure at the valve inlet expands the bellows to the extent that the hydraulic seating force on the pi1ot disc is reduced to zero. Opening of the pilot stage allows a pressu,re differential to develop across the second stage disc which opens the second stage disc, thus venting the chamber o*ver the main valve piston.
* This causes a pressure d1fferenttal across the main valve
________ . _____ -- _ _ _ _ _____ _JD .s.t.o O_-'t/.hLc Lo_p__e )']_s_tbe __m_aj r1- .v__aJ_y__e_._ J Ji e-S \Ls _a-r.:e-  p.r-i--n g- - - - ---- -
loaded valves that actuate when steam pressure at the i.nlet overcomes the spring force holding the valve disc closed.
This satisfies the Code requirement.
Each 0f the 11 SRVs discbarge st!?am throu,gh a discharge line to a point below the minimum water level in the suppression pool. fhe three SVs discharge steam directly to the drywell. In the depressurization mode, the SRV fs opened by a pneumatic actuator which o,pens the second stage d1sc. The main valve then opens as described above for the safety mode. The de,pressuri zatic()n mode provides rnntrol led depressurization of the reactor coolant pressure boundary.
All 11 of the SRVs function in the safety mode and have the cap.ability to operate in the depressurization mode via manual actuation from the contro1 room. Five of the SRVs are allocated to the Automatic Depressurization System (ADS). The ADS requirements are specified in LCO 3.5.1, "ECCS-Operating."
(continued)
* PBAPS UN IT 2                                      B 3.4-15                                        Revision No. 114
 
SRVs and SVs B 3,4.3
* BASES    (continued)'
APPLICABLE            The ovefpressure protection system must accommodate the most SAFETY ANALYSES      severe pressurization transient. Eva.l uati ons have determined that the ~ost Sev~re transient is the closure of all main steam isolation valves (MSIVs), followed by reactor scram on hi g,h neutron flux ( 1. e., failure of the direct s,cram associated with MSIV pos-ftion) (Refs. 1, 4 and 5),
For the purpose of the analyses, 12 SRVs and SVs are assumed to operate in tt:le safety mode. The a.nalysis results demonstrate that the design SRV and SV capacity is capable of maintaining reactor pressure below the ASME Code limit of 110% of vessel design pressure (110% x 1250 psig =
1375 psig). This LCO helps to ensure that the acceptance limit of 1375 psig-is met during the Design Basis ~vent.
From an overpressure standpoint, the design basis events are bounded by the MSIV closure with flux scram event described a.bove, Reference 2 discusses additional events that are expected to actuaie t~e SRVs and SVs. Although not a design basis event, the ATWS analysis demonstrates that peak vessel bottom pressure is less than the ASME Service Level C limit of 1,500 pstg, SRVs and SVs satisfy Criterion 3 of the NRC Policy
* LCO Statement.
              - ---The safety" functio~--,af any combinatio.n of-12 -SRVs and-SVs ______!__ _
are re~uired to be OPERABLE to satisfy the assumptions of the safety analysis (Refs. 1, 2, 4 and 5). Regarding the SRVs, the requirements of this LCO are applicable only to their capability to mechanically Open to relieve excess pressure when the lift setpoint is exceeded (safety mode).
The SRV and SV setpoints are established to ensure that the ASME Code 11mit oh peak reactor pressure is satisfied. The ASME Code specifications reqtiire the lowest safety valve setpoint to be at or below vessel design pressure (1250 psig) and the highest safety valve to be set so that the total accumulated pressure does not exceed 1101 of the design pressure for overpressurization conditions. The trans1ent evaluations 1n the UFSAR are based on these setpoints, but also include the additional uncertainties of
                        + 3% of the nominal setpoint to provide an added degree of cons,ervati sm.
Operation with fewer valves OPERABLE than specified, or with setpoi nts outs'i de the ASME limits, could result in a more severe reactor response ta a transient than pred1cted, possibly resulting in the ASME Code limit on reactor pressure being exceeded, (continued)
PBAP'S UN IT 2                            B 3.4-16                    Revision No. 148
 
SRVs and SVs 8 3 .. 4.3
* BASES LCO (continued)
If a second SRV or SV becomes inoperable leaving 12 operable SRVs/SVs and THERMAL POWER is above 3358 ftfwt, then Condition A must be entered. TilERMAL POWER may be. reduced to less than or equal' to 3358 MWt: within 12. hours from when the second SRV or SV became inoperable to exit Condition A. If repairs are made such that at least 13 SRVs/SVs are operable, then operations may resume at RTP.
If during PBAPS Unit 2 Cycle 22, a third SRV/SV inoperable leaving ll operable SRVs/SVs, then Condition A will require Unit 2 to be in Mode 3 within 12 hours from when one or more required SRV/SV became inoperable. If repairs are made such that 12 SRVs/SVs are operable_, then operati ans may resume at less than or equal to 3358 MWt. 'If repairs are made such that at least 13 SRVs/SVs are operable, then operations may r,esume at RTP.
(continued)
* PBAPS UNIT 2                        B 3.4-16a                    Revision No. 142
 
SRVs and $Vs B 3.4.3
* BASES  (continued)
APPLICABlLiiY
* In MnDES 1, 2, and ~, a11 required SRVs and SVs must be OPERABLE, since considerable energy may be in the reactor core and the limiting design basis transients a.re assumed to occur in these MODES. The SRVs and SVs may be required to provide pressure relief to discharge energy from the core untiT such time that the Residual Heat Removal (RHR) System is capable of dissipating the core heat.
In MODE 4, decay heat is low enough for the RHR System to provide adequate cooling, and reactor pressure is low enough that the overpressure limit is unlikely to be approa.c:hed by assumed operational transients or- accidents. In MODES, the reactor vessel head is unbolted or removed and tbe reactor is at atmospheric pressure. The SRV and SV function i.s not needed durlng these conditions, ACTIONS              A,1 and A.2 With less than the minimum numbe.r of required SRVs or SVs OPERABLE, a transient may result im the violation of the!
ASME Code limit on reactor pressure. If the safety function of one or more required SRVs or SVs is inoperable, the plant must be brought to a MODE in which the LCO does not apply.
th,
________ To_acbie'le .. s_.s:ta.tus, ..the- pl al'l.t .must be-br:ought -to -MODE - - - - - - - -
within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE          SR 3.4.3.1 REQUIREMENTS This Surveillance requires that the required SRVs and SVs wi11 open at the press.ures assumed in the safety analyses of References 1 and 2. The demonstration of the SRV and SY safety lift settings must be performed during shutdown, since this is a bench test, to be done in accordance with the INSERVICE TESTING PROGRAM. The 1ift setting pressure                      L shall correspond to ambient conditions of the valves at nominal operating temperatur,es and pressures. and b(:'! verified with insulation ins*talled simulating the in-plant condition.
The SRV and SY set point is +/- 3% for OPERABILITY. Prior to placing new or refurbished valves into service, the valve openings setpoints must be adjusted to be within+/- 1% of their nominal setting.
*                                                                                    (continued}
PBAPS UNIT 2                          B 3.4-17                            Revision No. 140
 
                                                                                    $RVs and SVs B 3.4.3
* BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.4.3.2 The pneumatic actuator of each SRV valve is stroked to verify that the second stage pilot disc rod is mech~nically d1spiaced when the actuator strokes. S~tond stage pilot rod movement is determined by the measurement of actuator rod travel. The total amount of movement of the second stage p11ot rod from the valve closed position to the open position Shall meet criterfa established by the SRV supplier. If the valve fails to actuate du~ ohly to the failure of the solenoid, but is capable Of openi~g on overpressure, the safety function of the SRV is considered OPERABLE.
The Surveillance Frequency 1s controlled under the Surveillance Frequency Control Program.
REFERENCES    1. NEDC-33566P, ttSafety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate,tt Revision 0 .
* 2. UFSAR, Chapter 14.
_3. "--N~1K.: J_2_2&8__:-A,_ Re'Lisiol'l __ 2., __ J_ec.bntcal_JustHJ cation-to- -- -- ---
Support Risk-Informed Modification to Selected Required End States for 8WR Plants, December 2002.
: 4. G-080-VC-413, "Reactor Vessel Overpressure Protection,"
GE Hitachi N~clear Energy, 26A8321, Revision 1.
: 5. G-080-VC-468, "Peach Bottom Units 2 & 3 Two Safety Relief Valves Out-of-Service Evaluation,w GE Hitachi Nuclear ~nergy, 004N6240-P, Revision 1 .
* PBAPS UNIT 2                            B  3.4-18                              Revision No. 148
 
RCS Ope.rational LEAKAGE B 3.4.4
* B 3. 4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.4 RCS Operational LEAKAGE BACKGROUND        The RCS includes systems and components that contain or transport the coolant to or from the reactor core. The pressure containing components Qf the RCS and the portions of connecting systems out to and inc lud i.ng the i sol at ion valves define the reactor coolant pressure boundary (RCPBJ.
The joints of the RCPB' components are welded or bolted.
During plant life, the joint and valve interfaces can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration.
Limits on RCS *operational LEAKAGE are required to ensure appropriate action iS taken before the hitegrity of the RCPB is impaired. This LCO specifies the types and limits of LEAKAGE. This protects the RCS pressure boundary described
                    *in 10 CFR 50.2, 10 CFR 50.SSa(c), and the UFSAR {Refs. 1, 2, and 3).                                                            .
The safety significance of RCS LEAKAGE from the RCPB varies widely depending on the source, rate, and duration.
Therefore, detection of LEAKAGE in the primary containment
                  -ts:-necessary-.--Methods-for-qui ckl y-separat i ng~ the-tc:lent-ifi-ed---~ - ,
LEAKAGE from the uni.denti fied LEAKAGE are necessary to provide the operators quantitative infonnation to .pennit them to take corrective action should a leak occur that is detrimental to the safety of the facility or the public.
A limited amount of leakage inside primary containment is expected from auxiliary systems that cannot be made 100%
leaktight. Leakage from these systems should be detected and 1.solated from the primary containment atmosphere., if possible, so as not to mask RCS operational LEAKAGE detection.
                    "this LCO deals wit~ protection of the RCPB' from degradation and the core from inadequate cooling, in addition to preventing the accident analyses radiation release assumptions from being exceeded.. The consequences of violating this LCO include the pos.si.bility of a loss of coolant accident~
{continued)
PBAPS UNIT 2                        B 3.4-19                          Revision No. O
 
RCS Operational LEAKAGE B 3.4.4 BASES (continued)
APPLICABLE        The allowable RCS operational LEAKAGE limits are based on SAFm ANALYSES    the predicted and experimentally observed behavior of pipe cracks. The normally expected background LEAKAGE due to equipment design and the detection capability of the instruraentation for determining system LEAKAGE were also considered. The evidence from experiments suggests that, for LEAKAGE even greater than the specified unidentified LEAKAGE 1 imi ts, the probability is sraa11 that the imperfection or crack associated with such LEAKAGE would grow rapidly.
The un 1dent if i ed LEAKAGE fl ow 1 i mi t a11 ows ti me for corrective action before the RCPB could be significantly compromised. The 5 gpm 1 1-mit is a sma 11 fraction of the calculated flow from a critical crack in the primary system pipi'ng. Crack behavior from experimental programs (Refs. 4 and 5) shows that, leakage rates of hundreds of gallons per m.i nute wi 11 precede crack i nstabil 1ty.
* The low limit on increase in unidentified LEAKAGr assumes a failure mechanism of intergranular stress corrosion cracking (lGSCC) in service sensitive type 304 and type 316 austenitic stainless steel that produces tight cracks. This flow increase limit is capable of providing an early warning of such deterioration.
No applicable safety analysis* assumes the total LEAKAGE li.mit., The total LEAKAGE 1 iudt considers RCS inventory makeup capability and drywell floor sump capacity.
RCS operational LEAKAGE satisfies Criterion 2 of the NRC Po1icy Statement.
LCO                RCS operational L~E shall be limited to:
: a. Pressure Boundary  LEAKAGE No pressure boundary LEAKAGE is allowed, since it is indicative of material degradation. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting ih higher L&#xa3;AKAGE.
Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.
{continued)
PBAPS UKIT 2                            B 3.4-20                          Revision No. O
 
RCS Operationa~ LEAKAGE B 3.4.4
* BASES LCO (continued)
: b. Unidentified LEAKAGE The 5 gpm of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and drywell sump level monitoring equipment can detect within a reasonable time period. Violation of this LCO could result in continued degradation of the RCPB.
: c. Total LEAKAGE The total LEAKAGE limit is based on a reasonable minimum detectable amount. The limit also accounts for LEAKAGE from known sources (identified LEAKAGE).
Viol,at1on of this LCO indi*cates an unexpected amount of LEAKAGE and, therefore, could indic~te 11~-or additional degradation in an RCPB compone*nt or system ..
: d. Unidentified  LEAKAGE Increase An  unidentified LEAKAGE increase of > 2 gpm within the previous 24 hour period indicates a potential flaw 1n the RCPB and must be quickly evaluated to detennine the source and extent of the LEAKAGE. The increase is
* measured relative to the steady state value; temporary
--~ -- ----- ----- --~------changes-in-L-E:Al<AGE....,-ate-as-a-re*sutt--of-transieni--~--
condit'ions (e.g., startup) are not considered. As such, the 2 gpm increase limit is only applicable in MODE l when oper,ating pressures and temperatures are established. Violation of this LCO could result in continued degradation of the RCPB.
APPLICABILITY      In MODES 1, 2, and 3, the RCS operational LEAKAGE LCO applies, because the potential for RCPB LEAKAGE is ,greatest when the reactor is pressurized.
In MODES 4 and 5, RCS operati'onal LEAKAGE limits are not required since the reactor i.s not pressurized and stresses in the RCPB materials and potential for LEAKAGE are reduc,ed.
{continued) .
* PBAPS UNIT 2                          B 3.4-21                      Revision No .. O
 
RCS Operational LEAKAGE B 3.4.4
* BASES ACTIONS (continued}
AJ.
With RCS unidentified or total LEAKAGE greater than the limits, actions must be taken to reduce the leak. Because the LEAKAGE limits are conservatively below the LEAKAGE that would constitute a critical crack size, 4 hours is allowed to reduce the LEAKAGE rates before the reactor must be shut down. If an unidentified LEAKAGE has been identified and quantified, it may be reclassified and considered as identified LEAKAGE; however, the total LEAKAGE limit would remain unchanged.
B.l  and  B.2 An. unidentified LEAKAGE increase of > 2 gpm within a 24 hour period is an indi'cation of a potential flaw in the RCPB and must be quickly evaluated. Although the increase does not necessarily violate the absolute unidentified LEAKAGE limit, certain susceptible components must be determined not to be the source of the LEAKAGE increase within the required Completion Ti1110. For an unidentified LEAKAGE increase greater than required limits, an alternative to reducing LEAKAGE increase to within 1 ililits (i.e., reducing the
* leakage ~ate such that the current rate is 1ess than the
                  .. - **~2-gpm-i ncrease-1 n-t-he--prev-'l--otls-2-4-houF-S*'!_-l 1art t-;-.e-tther-..by- -- -
isolating the source or other possible methods) is to evaluate service sensitive type 304 and type 316 austenitic stainless steel piping that is subject to high stress or that contains relatively stagnant or intermittent flow fluids and determine it is not the source of the increased LEAKAGE. This type piping is very susceptible to IGSCC.
The 4 hour Completion Time is reasonal>le to properly reduce the LEAKAGE fncrease or verify the source before tfie reactor must be shut down without unduly jeopardizing plant safety.
C.l and C.2 If any Required Action and associat~d Completion Time of Condition A or Bis not met or if pressure boundary LEAKAGE exists, the plant l'lll.lSt be brought to a MODE in which the LCO qoes not ~pply. To achieve this status, the plant must be brought to MODE 3 within 12 hours and to MO.DE 4 Within (continued)
PBAPS UNIT 2                              B 3.4-22                                    Revision No. 0
 
RCS Operational LEAKAGE B 3.4..4
* BASES ACTIONS      C.l and C.2    (continued) 36 hours. Tha allowed Completion Tlmes are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challeng.'ing plant safety systems.
SURVEILLANCE  SR  3.4.4.1 REQUIREMENTS The RCS LEAKAGE is monitored by a variety of instruments designed to provi d al arms when LEAKAGE is indicated and to quantify the various types of LEAKAGE. Leakage detection instrumentation is discussed in more detail in the Bases for LCO 3.4.5, "RCS Leakage Detection Instrumentation.h* Sump level and flow rate are typically monitored to determine actual LE:AKAGE r.ates; however, any method may be used to quantify LEAKAGE within the guidelines of Reference 6. The Surveillance Frequency is controlled under the Survillance Frequency Control Program .
* REFERENCES    1.
2.
3.
10 CFR 50.2, 10 CFR 50.55a(c).
UFSAR, Section 4.10.4~
: 4. GEAP-5620, "Failure Behavior in ASTM Al068 Pipes Containing Axial Through-Wan Flaws," April 1%8.
: 5. NUREG-75/067, "Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping of Boiling Water Reactors," October 1975.
: 6. Regulatory Guide 1.45, May 1973.
: 7. G.eneric Letter 88-01,. "NRC P.o~ition on IGSCC in BWR Austenitic Stainless Steel Piping," January 1988 .
* PBAPS UN IT 2                    B 3.4-23                      Re\lision No. 86
 
RCS Leakage Detection Instrumentation B 3.4.5
* B 3.4  REACTOR COOLANT SYSTEM (RCS)
B 3.4.5  Res Leakage Detection Instrumentati0n BASES BACKGROUND        UFSAR Safety Destgn Basis (Ref. 1) req,u'i res means for detecting and, to the extent practical, identifying the location of the source of RCS LEAKAGE. Regulatory Guide 1.45, Revision 0, (Ref. 2) describes acceptable methods for selecting leakage detection systems.
Lim--lts ori LEAKAGE from the reactor cool ant pressure boundary (RCPB) are required so that appropriate action can be taken before the integrity Of the RCPB is impaired (Ref. 2).
Leakage d.etection systems for Ure RCS are provided to alert the ope.raters when leakage rates above norma'l background levels are detected and also to supply quantitative rrrea.surement of leakage rates. In addition to meeting the OPERABILITY requirements,. the monitors are typically set to provide the most sensitive response without causing an excessive number of spurious alarms. The Bases for LCO 3.4.4, "RCS Operational LtAKAGE," discuss the limits on RCS LEAKAGE rates.
Systems for separating the LEAKAGE- of an identified source from an unidentified source are necessarj to provide prompt
          -~--- _a n.d___qJJ at1 U.:tat:f-v-a-.:1 n-f-e-Pma-t-i-e n---t-o---t-h e~o p.e-r at-o-r s-to----p-e-rmlt -'tn~l'll~- -
to take immediate corrective action.
LEAKAGE from the RCPB fnside the drywel l is detected by at least one of two independently monitored variables, such as sump level changes and dry~ell gaseous radioactivity levels.
The primary means of quantifying LEAKAGE in the drywe11 is the drywell floor drain sump monitoring system.
The drywell floor drain s~mp monitoring system monitors the LEAKAGE collected iii the floor drain sump. This unidentified LEAKAGE consists of LEAKAGE from contro1 rod drives, valve flanges or packings, floor drains, the Reactor Building* Closed Cooling Water System, and drywelT air cooling unit condensate drains, and any LEAK~GE not collected in the drywell equipment drafn sump.                                        '
An alternate to the drywell floor drain sump monitoring system- is the drywell equipment drain sump monitoring system, but only if the drywell floor drain sump is overflowing. The drywell equipment drain sump collects not only all leakage not collected in the drywel1 floor drain sump, but also any overflow from the drywell floor drain sump. Therefore, if the drywell floor drain sump is
* PBAPS UNIT 2                                    B  3.4-24                                        Revision No.      93
* RCS Leakage Detection Instrumentation B 3..4.5 BASES BACKGROUND                      overflowing to the drywell equipment dra.in s.urnp, the* drywell (continued)                  equipment drain sump monitoring system can be used to quantify LEAKAGE. In this condition, all LEAKAGE measured by the drywell equipment drain sump monitoring S,),'stem is assumed to be unidentified LEAKAGE.
* The fl0or drain sump level indicators have switches that start and stop the sump pump.s when required. If the sump fills to the high hig'h level setpoint, an alarm sounds in t~e control room, indicating a LEAKAGE rate into the sump 1n excess of 50 gpm.
A flow transmitter in the discharge line of the drywell floor drain sump pumps provides flow indici)tion in the control room. The pumps can also be started ,from the control room.
The primary containment air monitoring system continuously monitors the primary containment atmosphere for airborne gaseous radioactivity. A sudden signiffcant increase of radioactivity, which may be attributed to RCPB steam or water LEAKAGE, is annunciated in the control room.
* APPLICABLE                      A threat of s1 gnifi cant compromise to the RCPB exists if the
  - - - - -SA F-FPr'-A NA--1:.-Y-S ES-- - -b a-r r-1 e r--c on t-ai ns-a-*c r ac-Htra t -;-s-4 aT'Q e- en-oug tttcr pr op a ga re-----
r api d l y. LEAKAGE rate limits are set low enough to detect the LEAKAGE emitted from a single crack in the RCPB (Refs. 3 and '4). The allowed LEAKAG,E rates are well below the rates predicted for critical crack sizes (Ref. 6). Therefore, these actions provide adequate response before a significant break in the RCPB can occur.
RCS leakage detection instrumentation satisfies Criterion 1 of the NRC Policy Statement.
lCO                            This LC{) requires ins*truments of diverse monitoring principles to be OPERABLE to provide confi<lence that small amounts of unidentified LEAK.AGE are detected in time- to allow actions to place the plant in a safe condition, when RCS LEAKAGE indicates possible RCPB degradation.                '
The LCD requires two instruments to be OPERABLE.
The drywell sump monitoring system is required to quantify the unidentified LEAKAGE from the RCS. Thus, for the system to be cons1~ered OPERABLE, the system must be capable of
* PBAPS UNIT 2                                                B 3.4-25                                Revision No. 93
 
RCS Leakage Detection Instrumentatfon B 3.4.5 BASES LC0          measuring reactor coolant leakage. Th1s may be acco~plished (continued) by use of the associated drywell sump flow integrator, flow recorder, or the pump curves and drywell sump pump out time.
The system consists of a) the drywell floor drain sump monitoring system, orb) the drywell equipment drain sump monitoring system, but c0nl y when the drywell floor drain sump is overflowing. The identification of an iDcrease in uni denti fi ed LEAKAGE wi 11 be delayed by the time required for the uni dent1fi ed LEAKAGE to travel to the drywel1 sump and H may take longer than one hour to detect a 1 gpm increase in unidentified LEAKAGE, depending on the orfgin and magnitude of the. LEAKAGE. This sensitivity is acceptable for containment sump mon1tor OPERABILITY.
The reactor coolant contains radioactivity that, whet1 r.eleas,ed to the primary conta.inment, can be detected by the gaseous primary containment atmospheric radioactivity monitor. Only one of the two detectors is required to be OPERABLE. A radioactivity detection system is included for monitoring gaseous activities because of its sensitivities and rapid responses to RCS LEAKAGE, but it has recognized limitations.
Reactor coolant radioactivity levels will be low durtng initial reactor startup and for a few weeks thereafter, until activated corrosion products have been formed and fission products appear
* _
* from fuel element c]adding contamination or cladding de.fects.
  - - - ----- - ----~-- H~H1ere-are--few -fue'.J---el-ement--claddi-ng -defects-c1nd-1*ow, eve-1-s-of activation products, it may not be possible for the gaseous primary containment atmospheric radioactivity monitor to detect a 1 gpm increase within 1 hour during normal operation.
However, the gaseous primary containment atmospheric radioactivity monitor is OPERABLE when it is capable of detecting a 1 gpm increase in unidentified LEAKAGE within 1 hour given an RCS activity eq~ivalent to that assumed in the design calculations for the monitors (Reference 6).
The LC0 is satisfied when*monitors of diverse measurement means are available. Thus, the drywell sump monitoring system, in combination with a gaseous primary c::ontainment atmospheric radioactivity monitor provides an acceptable minimum.
APPLICABILITY In MODES 1, 2, an*d 3, leakage detection systems are required to be OPERABLE to support LCO 3.4.4. This Applicability is consistent with that for LC0 3.4.4.
(continued)
* PBAPS UN IT 2                      B 3.4-,26                            Revision No. 93
 
RCS Leakage Detection Instrumentation B 3.4.5
* BASES (continued)
ACTIONS          A.l, A,2. and A.3 With the drywell sump mchitoring system inoperable, the .only means of detecting LEAKAGE is the primary containment atmospheric gaseous radiation monitor. The primary containment atmospheric gaseous radiation monitor typicany cannot detect a 1 gpm leak within one hour when RCS activity is low. In addition, this configurat5on does not provide the required diverse means of leakage detection. Indirect methods of monitoring RCS leakage must be implemented.. Grab s-amples of the primary contair.ment atmosphere must be taken and analyzed and l'lOnitoring of RCS leakage by administrative means must be.
performed every 12 hours to provide alternate periodac information. Tfe definition of grab sample wouid not preclude using installed accurate jnstrumentation to take a grab sample (Which can be defined as a single ~easurement at a discrete point in time). A TS, TRM, or ODCM Required Action/ Required Compensatory Measure requiring a grab sample be taken may 1nclude the use of installed avail2ble instrumentation that, although potentially inoperable, still provides a valid process measurement at a specific point in t1~e.
Administrative means of monitoring RCS leakage ir.clude monitor~ng ana tre'lding paral'leters that may indic:ate a*n increase I --- ----- -
in RCS leakage. There are diverse alternative mechanisms from which appropriate indicators may be selecte~ based on plant cond'iti ~ It 1s D..Q_t.,__n_e_c.e_s_s_a.r:y___J.o_ut.iJ tze...--a.l-l~-0f -thsse -- - - - - -----_- -
methods, but a met1oa or me:hods should be selected considering tne current plant conditiorys and historical or expected sources of unidentified leakage. The administrative methods are drywell pressure and temperatu'fe, Reactor Reci rc_ul ati on System pump s.eal pressure and temperature a:id motor cooler temperature indications, and sa~ety Relief V~lves tailpipe temperat~re.
These indicatfons, coupled with tfe atmcspheric grab sam~les, are sufficient to a1ert the operating staff to an unexpected iPcrease in uDidentified LEAKAGE.
The 12 hour inte~val is sufficient to detect increasing ~CS leakage. The ReqJired Action provi~es 7 days to restore another RCS leakage monitor to OPERABLE status to regain the ~ntended leakage detection diversity. The 7 day Completion Time ensur~s that the plant will not be operated i~ a degraaed configuration for a 1e'lgthy ti me: period.
8,1 and B.2 Wi~h the gaseous prim~ry containment 3tmospherfc monitoring channel inoperable, grao samples of the primary containment atmosphere must be taken and analyzed for gaseous radioactivity to provide periodic leakage information.
Providec a sample is obtafned and analyzed once every 12 hours, the p1ant may De ope.rated for up to 30 clays tc al1ow restoration of the recuired monitor.
PBAPS UN IT 2                        s 3.4-26a                                        Revision No. 152
 
RCS Leakage Detection Instrumentation B 3.4.5
* BASES
          ---------~----------------~--------
ACTIONS          s*.1 and B.2      (\:Ontinued)
The 12 ho~r interval provides periodic fnformation that is adequate to d.etect LEAKAGE. The 30 day Comp*l et ion Ti me .for
                            ~estoration recogni~es that at lea~t one other form of leakage detection 4s available.
: c. 1    and  c. 2 If any Required Action a*nd associated Completion Time of Condition A 0r B cannot be met, the plant must be brought to a MODE 1 n whi c.h the LCO does not apply. To achi eve this status, the plant must be brought to at least MODE 3 within 12 hours and MODE 4 within 36 hours. The.a1lowe<l C.ompletion Times are reasonable, based on operating experience, to perform tha actions in an orderly manner and without challenging plant sy~tems.
:D.....l With all required monitors inoperable, no required automatic
* means      of monitoring LEAKAGE are available, and immediate
-------------- ___________ j}lant shutdo,wn in *accordance with lCO 3.0.3 is required.
                                        -~-----~----~--~--------~- --~-~---.......... - - ~ - -
SURVEILLANCE      SR 3.4.5.1 REQu:r REMENTS This SR is for the performance of a CHANNEL CHECK of the required primary containment atmospheric monitoring system.
The check gives reasonab1e confidence that the channel is
                          ~perating properly. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .
* PBAPS UN IT 2                          B 3.* 4-27                    Revision No. 86
 
RCS Leakage Detection Instrumentatioh
: 8. 3 .4. 5 BASES SURVfl LLANCt  SR 3.4.5.2 REQUIREMENTS (continued)  This SR is for the performance of a CHANNEL FUNCTIONAL TEST of the required RCS leakage detection i nstrumentatfon. The test ensures that the monitors can perform their function in the desired manner. The test also verif1es the alarm setpoint and relat1ve accuracy of the instrument string.
              ~ The Survei l la nee Frequency is cohtro1 led under the Surveillance Frequency Control Program.
SR 3.4.5,3 This SR is for the performance of a CHANNEL CALIBRATION of required leakage detection instrumentation cha.nne1s. The calibration verifies the accuracy of the instrument string.
The Survei l la.nee Fre.quency is controlled under the Surveillance Frequen~y Control Program.
REFERENCES      L    UFSAR, Section 4.10.2.
2.. Regulatory Guide 1.45, Revision O, "Reactor Coolant Pressure Boundary leakage Detection Systems," May 1973.
: 3. GEAP-5620, "F,ai lure Behavior in ASTM Al06B Pipes Containing Axial Through-Wall Flaws," April 1968.
: 4. NUREG-75/067, "Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping of Boiling Water Reactors," October 1975.
: 5. UFSAR, Section 4.10.4.
: 6. UFSAR, Section 4.10.3.2.
PBAPS UNIT 2                        B 3.4-28 .                  Revision No. 93
 
RCS Spec1f1c Activity
                                                                              .          B 3.4.6 B 3.4  REACTOR COOLANT SYSTEM (RCS)
B 3.4.6  RCS Specific Activity BASES BACKGROUND          During circulatio~. the reactor coolant acquires radioactive mater1als duet~ release of fission products from fuel ,eaks into the reactor coolant and activation of corrosion prodlJcts in the r,eactor cool ant. These rad1oacti ve mater1als in the reactor coolant can plate out 1n the RCS, and, at times, an accumulation will break away to spike the normal level o-f rad1 oacti vity. The rel ease of cool ant durin,g a Design Basis Accident (DBA) could send rad1oactive materials into the environment.
Lim1ts on the maximum allowable leve1 of radioactiv1ty in the reactor coolant are established to ensure that in the event of a release of any radioactive material to the environment during a DBA, radiation doses are mainta1ned within the lim1ts of 10 CFR 50.67 (Ref, 1).
This LCO contains the iodine specific activity limits. The 1
                            ,1odine isotopic act1vities per gram of reactor coolant are expressed in terms of a ,DOSE EQUIVALENT I -131. The a 11 owab le 1evel 1s intended to 1i mi t the maxi mum 2 hour radiation dose fa-an, ncffvicfITa1-a~--vfesHe-rnrrda;ry-*tc,-* ------
within the 10 CFR 50.67 limit as modified in Regulatory Guide 1.183, Table 6.
APPLICABLE          Ana*1ytical methods and assumptions involving radioactive SAFETY ANALYSES    material in the primary coolant are presented in the UFSAA (Ref. 2). The specffic activity in the reactor coolant (the source term) is an initial condition for eva1uat1on of the consequences of an accident due to a rnain steam line break (MSLB) outs1de containment. No fuel damage is postulated in the MSLB aco1 dent, and the rel ease of radioactive material to the ~nvironment 1s assumed to end when the main steam isolation valves (MSIVs) close completely.
Th1 s MSLB rel ease forms, the basis for detenni n1 ng offsi te doses (Ref. 2). The limits on the specif1c act1vity of the primary coolant ensure that the maximum 2 hour TEDE doses at the sit.a boundary. resulting from an MSLB outside conta1nment during steady state operation, Will not exceed the dose guide11.hes of 10 CFR 50.67 as modified, in Regulatory Guide 1.183, Table 6 .
* PBAPS UNIT 2                            B 3.4-29
{continued)
Revi.sion No. 75
 
RCS Specific Activity B 3.4.6 BASES APPLICABLE            The limits on specific activity are values from a *parametric SAFETY ANALYSES        evaluation of typical site locations. These 11m1ts are (continued)        conservative because the evaluation considered more restr1ct1ve parameters than-for a specific s1te, such as the location of the site boundary and the meteorolog1cal conditions of the site.
RCS specific activity satisfies Criterion 2 of the NRC Policy Statement.
LCO                    The specific iodine activity is limited to::::: 0.2 &#xb5;C1/gm DOSE EQUIVALENT I-131. This limit ensures the source term assumed in the safety analysis for the HSLB is not exceeded, so any release of radioactivity to the environment during an HSLB is within the 10 CFR 50.67 limits as modified in Regulatory Guide 1.183, Table 6.
APPLICABl LITY        In MODE 1, and HODES 2 and 3 with any main steam line not isolated, limits on the primary coolant radioactivity are applicable since there fs an escape path for release of
,.....-- - - -- - ,~ --  ---- -- - - - --
radioactive material from the primary coolant to the environment in the event of an MSLB outside of primary
                                            *containment.
                                            ......--------.- - - - - - - - - - ~ - - - - ~ - -=---------
In HODES 2 and 3 With the maih steam lines isolated, such limits do not apply since an escape path does not exist. In MODES 4 and 5, no limits are required since the reactor is not pressurized anp the potential for leakage is reduced.
ACTIONS                A.1 and A.2 When the reactor coolant specific activity exceeds the LCO DOSE EQUIVALENT I-131 limit, but is::::: 4.0 &#xb5;Ci/gm, samples must be ana1yzed for DOSE EQUIVALENT I-131 at least once every 4 hours. In aadition, the specific .activity must be restored to the LCO limit within 48 hours. The Completion Ti me of once every 4 hou*rs is based on the ti me needed to take and analyze a sample .. The 48 hour Completion Time to restore the activity level provides a reasonable time for temporary coolant acttvity increases (iodine spikes) .to be cleaned up with the normal processing systems.
(continued)
* PBAPS UNIT 2                                B 3.4-30                                      Revision No. 75
 
RCS Specific Activity B 3.4.6
* BASES ACTIONS            A.1 and A.2    (continued)
A Note permits the use of the provisions of LCO 3.0.4.c.
This an owance permits entry into the applicable MODE (S) while relying on the ACTIONS. This allowance is acceptable due to the significant conservatism incorporated into the specific activity limit, the low probability of an event which 1s limiting due to exceeding this limit, and the ability to restore transient specific activity excursions while the plant rema1ns at, or proceeds to, power operation.
B.1. B.2.1. B.2.2.1. and B.2.2.2 If the DOSE EQUIVALENT I-131 cannot be restored to~ 0.2
                      &#xb5;Ci/gm within 48 hours, or if at any ti*me 1t is> 4.0
                      &#xb5;Ci/gm, 1t must be determined at least once every 4 hours and all the main steam lines must be isolated within 12 hours. Isolating the main steam lines preoludes the possibility of releasing rad1oactive material to the environment in an amount that is more than the requirements of 10 CFR 50.67 as modified in Regulatory Guide 1.183, Table 6, during a postulated MSL8 accident.
_____ L_~ __ Alternat-f~~!.YL_!t:!,e plant .can be placed in HOOE 3 within 12 hours and in MODE4 within -36 hourf:---rfrfsoptfon i,--,s~-
provi ded for thos.e instances when i sol ati on of main steam lines is not desired (e.g., due to the decay heat loads).
In MODE 4, the requirements of the LCD are no longer applicable.
The Completion Time of once every 4 hours is the time needed to take and analyze a samp1e. The 12 hour Completion Time is reasonable, based on operating exparience! to isolate the main steam lines in an orderly manner and without challenging plant systems. Also, the allowed Completion Times for Required Actions 8.2.2.1 and 8.2.2.2 for placing the unit in MODES 3 and 4 are reasonable, based on operating experience, to achieve the required plant conditions from full power condi ti ans in an orderly manner and without challenging plant systems.                            -
(continued)
* PBAPS UNIT 2                            8 3.A-31                      Revision No. 75
 
RCS Specific Activity B 3.4.6 BASES  (continued)
SURVEILLANCE        SR 3.4.6,I REQUIREMENTS Thi& Surveillance is performed to ensure iodine remains with-In lirrii't during normal operat1on. The Surveillance Frequency is controlled under the Survei 11 ari*ce Frequency Control Program.
This* SR is mod'ifie-d by a Note that requires this Surveillance to be performed only ln MOD&#xa3; 1 because the level of f1 ss1 on products generated in other MODES , s much less.
REFERENCES          l. 10 CFR 5Q.67.
: 2. UFSAR, Section 14.6.S .
* PBAPS UN IT 2                            B 3.4-32.                  Revision N*o. 86
 
RHR Shutdown Cooling System-Hot Shutdown B 3.4.7
* B 3.4 B 3!4.7 BASES REACTOR COOLANT SYSTEM (RCS)
Residual Heat Removal (RHR) Shutdown Cooling System ..... Hot Shutdown BACKGROUND          Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed to reduce the t81111)erature of the reactor coolant to
:S 212*F. This decay heat removal is in preparation for perfo_rming refueling or maintenance operations, or for keeping the reactor in the Hot Shutdown condition.
The RHR System has two loops with each loop consisting of two motor driven pumps, two heat exchangers, and associated -
piping and valves. lhe~e are two RHR shutdown cooling subsystems per RHR System loop. Both loops have a cormnon suction from the same recirculation loop. The four redundant, manually controlled shutdown cooling subsystems of the RHR System provide decay heat removal. Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to the reactor via the associated rec.irculation loop. The RHR heat exchangl;!rs transfer heat to the High Pressure Service Water (HPSW)
System. Any one of the-four RHR shutdown cooling subsystems
      ~- -- -----can--provide-the,equired-decay-heat-remova-l-funct:ion-;-----------
APPLICABLE        Decay heat removal by ,operation of the RHR System in the SAFETY ANALYSES    shutdown cooling nt0de is not required for mitigation of any event or accident evaluated in the safety analyses. Decay heat removal 1st however, an important safety function that must be accomplished or core damage could result. The RHR Shutdown Cooling System meets Criterion 4 of the NRC Policy Statement.
LCO                Two RHR shutdown cooling subsystems are required to be, OPERABLE, and when no recirculation pump iS in operation, one shutdown cooling subsystem must be in operation. An OPERABLE RHR shutdown cooling subsystem consists of one OPERABLE RHR pumpr ,one heat exchanger, a HPSW PUIIIP capable of providing c:ooling to the heat exchanger, and the -
associated piping and valves. The two subsystems have a co11JDOn suction source and are allowed to have coQJOOn discharge piping. Since piping is a passive component that Ccontjnued)
PBAPS UNIT 2                          B 3.4-33                        Revision No. 0
 
RHR Shutdown Cooling System-Hot Shutdown B 3.4.7
* BASES LCO (continued) is .assumed not to fail, it is allowed to be common to both subsystems. Each shutdown cooling subsystem is considered OPERABLE if it can be manually al'igned (remote or local) in the shutdown cooling mode fo.r removal of decay heat. In MODE 3, one RHR shutdown cooling subsystem can provide the required cooling, but two subsystems are required to be OPERABLE to provide redundancy. Operation of one subsystem can ~aintain or reduce the reactor coolant temperature as required. Hbwever, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operatiot:1 is required. Management of gas voids is important to RHR Shutdown Cooling System OPERABILITY.
Note 1 permits both requtred RHR shutdown cooling subsystems and recirculation pumps to be shut down for a period of 2 h,ours in an 8 hour period. Note 2 allows one required RH,R shutdown cooling subsystem to be inoperable for up to 2 hours for performance of Surveillance tests. These tests may be on the affected RHR System or on some other plant system or component that necessitates placing the RHR System in an inoperable status during the rerformance. This is permitted because the core heat generation can be low enough
*            ,            and the heatup rate slow enough to allow some changes to the
------------ ------ *- -~- ----RHR-s*utrsystems--o--r--oth-er oirerat1onsrequ-frTng-Rl{lCTiow -
interruption and loss of redundancy.
APPLICABILITY      In MODE 3 with reactor steam dome pressure below the RHR shutdown cooling isolation pressure (i.e., the actual pressure at which the RHR shutdown codling isolation pressure setpoint clears) the RHR Shutdown Cooling system must be OPERABLE and shall be operated in the shutdown cooling mode to remove decay heat to reduce 0r maintain coolant temper.ature. Otherwise, a recirculation pump is required to be in operation.
ln MODES 1 and 2, and i"n MODE 3 With reactor steam dome
* pressure greater than or equal to the RHR shutdown cooling isolation pressure, this LCO is not applicable. Operation of the RrlR System in the shutdown cooling mode is not allowed above this pressure because t~e RCS pressure may exceed the design pressure of the shutdown cooling piping.
Decay heat removal at reactor pressures greater than or equal to the RHR shutdown cooling isolation pressure is typically accomplished by condensing the steam in the main condenser.
PBAPS UNIT 2                              B 3.4-34                        Revision No . 126
 
RHR Shutdown Cooling System-Hot Shutdown B 3.4.7
* BASES AP PU CAB I LI TY (continued)
Additionally, i'n MODE 2 be1ow this pressure, the .QPERABILITY requirements for the Emergency Core Cooling Systems (ECCS)
(LCD 3.5,1, "ECCS-Operating") do not allow placing the RHR SFlutdown cooling subsystem into operation.
The retju1rements for decay heat removal in MODES 4 and 5 are discussed in LCD 3.4.8, "Residual H~at Removal (RHR)
Shutdown Cooling System-Cold Shutdown": LCO 3.9.7, "Re_sidual Heat Removal CRHR)-High Water Level"; and LCD 3.9.8, "Residual Heat Removal CRHR)-Low Water Level."
ACTIONS
* A Note has been provided to modify the ACTIONS related to RHR shutdown c.ooling subsystems. Section 1.3,
___________ CoJlll)_l eti on_ Ti mes_,_ sReci fi e.s__QJl~_g_COndi ti o_n_b~_s__b...e.Brr_ ______ _
entered, subsequent divisions, subsystems, components qr variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate en t ry i nto the Con di ti on . Sect i on I. 3 a l so spec if i e s Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condi ti on. However, the Required Actions for inoperable shutdown cooling subsystems provide appropriate compensatory measures for separate inoperable shutdown cooling subsystems. As such, a Note has been provided that allows separate Condition entry for each inoperable RHR shutdown cooling subsystem.
A.1,    A.2. and A.3 With one required RHR shutdow~ cooling subsystem inoperable for decay heat removal, except as permitted by LCO Note 2, the inoperable subsystem must be r~stored to OPtRABLE sti;ltus without delay. In this condition, the remaining OPERABLE subsystem can provi~e the necessary decay heat removal. The continued PBAPS UN IT 2-                            B 3.4-35                            Revision No. 52
 
RH~ Shutdown Cooling System-Hot Shutdown B 3.4.7 *
* BASES ACTIONS      A.I, A,2. and  A::3  (continued) overall re11ability is reduced, however, because a singl~
failure in the* OPERABLE subsystem could result in reduced RHR shutdown cooling capability. Therefore, an alternate method of decay heat removal must be provided .*
Wtth both required. RHR shutdown :cooling subsystems inoperable, an alternate method of decay heat removal must be provi.ded in. addition. to that provided for the initial RHR shutdown coo 11 ng* subsystem. i noperabil i ty.. This
* re-establ 1shes backup decay heat removal capabilities, similar to the requirements of the LCO. The 1 hour              .
Completion Time is .based on the decay heat removal function and the probability of a Joss of the available decay heat removal capabilities.
* The required cooling capacity of the alternate method should be ensured by ve.rifying (by calculation or demonstration) its capability to maintain or reduce temperature. Decay heat removal by ambient losses can- be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not Umited to) the Condensate/Main SteiPI Systems and the Reactor Water Cleanup System.
However, due to the potentially reduced reliability of the alternate methods of decay heat removal, it is also reql{ired to reduce the reactor coolant temperature to the point )lhere MODE 4 i's entered.
* B, l, B, 2, and B, 3 With no RHR shutdown cooling subsystem and no recirculation pump in operation, except as permitted by LCO Note l, reactor coolant ciTC11latio11 by the RHR shutdown cooling subsystem or recircuht1on pump must be restored without delay..
* Until RHR or reci rcul at ion pump operation is re-est ab1bhed, an alternate method of reactor coolant circulation must be placed into service. This will provide the necessary circulation for monitoring coolant temperature. The l hour Completion Time 1s based on the coo.lant circulation function and 1.s modified such that the 1 hour is applicable s*eparately for each occurrence involving a loss of coolant Ccontinued}
PBAPS UNIT 2                      B 3.4-36                        Revision No. O
 
RHR Shutdown Cooling System-Hqt Shutdown 8 3.4.7
* BASES ACTIONS            B.l. B.2. and B,3          (continued) circulatiorr. Furthermore, ~erification of the functioning of the al te:rnate method must be reconfirmed every 12 h*ours there,aftet. Thi.s wil1 l)tovide assurance o'f continued temperature monitoring capabil1ty.
During the period wh~n the reactor coolant is being circulated by an alternate method (oth:er than by the required RHR shutdo'fm cooling subsystem or reci rcul ati on pump), the .reactor rnolant temperature and press1:1re must be periodic,ally mo:nHored to ensure proper function of the alternate method. The once per hour Completion Time is deemed appropriate.
SURVE'I LLANCE      SR    3.4.7.1 RE,QU IREME,NTS This Surv,ei 11 ance veri.fi es that one required RHR shutdown cooling subsystem or recirculation pumR is in operation and circulatin.9 reactor coolant. The requ,red. flow rate is determined by the flow rate necessary to pfovide sufficient decay heat removal capability. The Surveillance Frequencij is controlled under the Surveillance Frequency Control
--~- - _,_ ---- --*-- --~--prt;gr=a:nr:---- -----~--- *--~-~-~-                                          -~ -----~**,- -
This Surveillance is modified by a Note allowing sufficient time _to allgn the RHR System for shut(fown cooHr.ig operation after clearing the pressure s~tpoint that isolates the system, or for plating a recirculation pump in operation.
The Note takes exception to the requirements of the S-u r ve i 77 a nce be i ng met ( i. e ., f o r ce d cool a h t c i r c ul a t i 011 'i s 0
not require.d for th.is initial 2 hour period), which ..also allows entry irito the Ap.plica.bilfty of this Specification in accordan.ce wfth SR 3.0.4 since the Surveillance will not b..e "not met'' at the time *of e:ntry into the Applicability.
SR    3.4.7.2 RHR Shutdown Cooling ( SOC) System piping and components lilave the potential to develop voids and pockets of entrained gases,          P~ev~nting and managing gas lntrusion and accumu1atton is necessary for ~roper o~eration of the required RHR sh1,1tdowrv cooling subsystems and may a1;50 prevent water hammer, pump (;avitation, and pumping of noncondensi Dl e gas into t~e reactor vessel .
PBAPS UN Ir 2                                B 3.4-37
 
RHR Shutdown Coo.ling System-Hot Shutdown B 3.4.7
* BASES
  ------~-~---------------------------
SUR VEIL LANCE    SR 3.4.7.2 (Continued)
REOU rREMENTS Se1ection of RHR Shutdown Cooling System locations susceptible to (:las accumulation is based on a review of system design information, including piping and instrumentation drawingsj isometric drawings, plan and elevation drawings,. calculations, ahd operational procedures.              The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become .sources of gas or could otherwise cat1se gas to be trapped or di ffi cult to remove during system ma i ntenanc-e or restoration. Susceptible locations d~pend on plant and system configuration, such as stand-by versus -operati*ng conditions.
The RHR Shutdown Coolfng System is OPERABLE when it is suffi ci*ent1 y filled wHh water. For the RHR SOC piping on the discharge .side of the RHR pump, acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location Co~ the volume of accumulated gas at one or more susceptible locatfons exceeds an acceptan:ce criteria for gas volume in the RHR SOC piping on the d'1 sch a rge side of a -
pump), the Surveillance is not met.                          If the accumulated gas is eliminated .or,orought .W1thin the acceptance c*riteria
    -~" ~ -- -  ~- -l i-m-i-t--s-dtl r-i-n g--per fo rtrra-n ce--o f-tt, e- Surv e ;-;i-1--a-n ce-;-th-e--S-R:-'i"S-*me t-- ~--
and. past system OPERABILITY is. evaluated 1.:Lhder the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Shutdown Cooling Sy~tem is not rendered inoperable by thi accumulated gas (i.e .* the system is sufi'i der:itl y fi 17 ed with water), the Su rvei l J ance may be declared met. - Accumulated gas should be eliminated or brought within the acceptance criteria limits. Since the RHR SOC pi p*i ng on ttie discharge side of the pump is the same as the Low Pressure Coolant Injection piping, performances o,f survei 71 ances for ECCS T3 may satisfy the requirements of this_ survei 17 ance-. For the RHR SOC pi pi.ng on the suction side of the RHR pump, the surveillance is met by virtue of the performance of operating procedures that ensure that the RHR SOC -suction piping is adequately filled and vented.                  The performance Of these manual actions ensures that the .surveillance is met.
RHR SOC System locations on the discharge side of the RHR pump susceptible to gas accumul a.ti on are monitored and, if gas is found, the gas volume is compared to the acc~ptance criteria for the location. Susceptible locatfons in the same system flow path which are subject to the same gas C
* PBAPS UN IT 2                                  B 3.4-37a                                      Revision No. 127
 
                                                      "RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 BASES SURVEILLANCE        SR 3.4.7.2        (continued)
REQUIREMEN1S intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations.
Mor:iitoring may not.be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel sa.fe.ty.
For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location.          Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and det"ermi ned to not challenge system OPERABILITY. The accuracy of the method used for monitoring the. susceptible locations and trending of the results should be sufficient to assure system OPERABl LITY during the *survei 11 ance interval.
The SR may be met for one RHR SOC subsystem by virtue Of having a subsystem in service in accordance With operating procedures.
Thfs SR is modified by two Notes.              Note 1 that states the SR is not required to be performed until 12 hours after
  - * -- - - - -~- -- --- -- -rea-ct-o-r* -steam -ctome*-pressure* i s-*less *than* the** RHR*-Shutd*own~
Cooling System Isolation reactor pressure allowab1e value in TS Table 3.3.6.1-1. In a rapid shutdown, there may be ins~fficient time to verify all susceptible locations prior to entering the APP,l i cabil ity.
Note 2 to the Surveillance recognizes that the ~cope of the surveillance is limited to the RHR system components. The HPSW system components h~ve been determined to not be required to .be in the scope of th'is surveill.ance due to operating experience and the design of the system.
The Surveillance Frequency is controlled under the Survei1lance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation.
REFERENCES          None .
* PBAPS UN IT 2                              B 3.4-37b                          Revision No. 126
 
RHR Shutdown Cooling System-Cold Shutdown B 3.4.8
* B 3.4 REACTOR COOLANT SYSTEM (RCS}
B 3.4.8 Residual Heat Removal (RHR} Shutdown Cooling System-Cold Shutdown BASES BACKGROUND        Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat JDUst be removed to maintain the. temperature of the reactor coolant
:S 212*F. This decay heat removal is in p.reparation for performi~g refueling or maintenance operations, or for keeping the reactor in the Gold Shutdown condition.
The RHR System has two loops w.i th each loop consisting of two motor driven pumps, two heat exchangers, and associated piping and valves. There are two RHR shutdown cooling subsystems per RHR System loop. Both loops have a conunon suction from the same* recirculation loop. The four redundant, manually controlled shutdown cooling subsystems of the RHR System provide decay hea,t removal. Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to the reactor via the
  ~-                        associ'ated rectrculation loop.. The. RHR heat exchangers transfer heat to the High Pressure Service Water (HPSW}
* System. Any one of the four RHR shutd.own cooling subsystems
- - --- ---~-~- -- --- - --can--provi de--the--requested-decay heat--remova l-functi on-:-=-- -- -~ --- -
APPLICABLE        Decay heat re1J10val by operation of the RHR System in the
* SAFETY ANALYSES  shutdown cooling mode is not required for mitigation of any e.vent' or accident evaluated in the safety analyses. Decay heat removal is, however, an important safety function that must be accomplished or core damage could .result. The RHR Shutdown Cooling System meets Criterion 4 of the NRC Policy Statement.
LCO              Two RHR shutdown cooling subsystems, are Tequired to be OPERABLE, and When no recirculation pump is- in operation, one RHR shutdown cooling subsystem must be in operation. An OPERABLE RHR shutdown cooling subsystem consists of one OPERABLE RHR pump, one heat exchanger, a HPSW pump capable of providing cooling to the heat ex~hanger, and the associated piping and valves. The two subsystems have a coDJnOn suction source and are allowed to have conanon discharge piping. Since piping 1s a passive component that is assumed not to fail, it is allowed to be tOllllK)n to both
*                                                                                {continued}
PBAPS UNIT 2                        B 3.4-38                        Revision No. O
 
RHR .s'h1Utdown Cool 1rig System-Cold Shutdown B 3.4.8
* BASES LCD (continued) subsystems. ln Moor 4, the RH~ ~ross tie valve (M0-2-10-020)-may be opened (per LCD 3.5.2) to allow pum~s in o.ne: loop to discharge througq the opposite reci rcul ati on
                          .loop to make a complete subsystem. In ad.dition, the HPS}J cross-tie valve may be opeliled to all ow an HP.SW pum*p in on,e loop to provide cooling to a heat exthange~ in the opposite loop to make a complete s-ubsystem. Additionally, each shutdown cooling subsystem is considered OPERABLE if it can be manually a.liglled (remote or local) in the shutdown cooling mode for r-emova1 of (!ecay heat. In MOOE 4, one RHR shutdown cooling ~ubsystem can provide the required cooling, but two subsystems are required to be OPERABLE to provide redundancy. Opera ti on of one subsyste(ll can ma.i ntai n or redll.Ce the reactor coolant tempergture as re.quired.*
However, to e.hsure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required. Management of gas voids is important to RHR Shutdown Codling System OPERABILITY.
Note 1 per'mi ts both required RHR shutdown cooling subsystems tc be shut down for a period of 2 hours in an 8 hour period~
Note 2 a11 ows one required Rl:lR s.hutdown cool it'.lg subsystem to be inoperable for up to-2 hours for performance of Survei 11 ance tests. These tests may be on the affected RHR
        . -~ ~ - - - ~ ~---&#xa3;-y .,st-e m..'.-0 r- e 19 s om e -o-t-h*e--r
* p1/4flt---sy-s-t-em~ mp on-en t -t'h a t~~.~-- ~~
* necessitates placing 1;he R'HR System in an inoperable s1;atus duri rig the performance. TM s is permitted because the core heat generation can be low enough and the heatup rate slow enough to allow some changes to the RHR subsystems or other operations requiring RHR flow int~rruption and loss of redundancy.
AP'PLICABI LITY          In MODE 4., the RHR Shutdown Cooling System must pe OPERAS LE aQd shall be operated in the shutdown cooling.mode to remo~e decay he~t t0 maintain coolant temperature below 212&deg;F.
Oth,erwise, a recirculation pump is required to be in op er.at ion.                                                ,
In MODE$ land 2, and in MODE 3 with reactor steam d.ome pressure great'er tban or equal to the RHR shutdown co,oling i.sol,ation pre.ss,u-re, this LCD is not applicable. Operation Qf the RHR SYstem in the. shutdown cool tng mode is'. not al 1owEd above thi. s pressure because the RCS pressure m1;1y exteed the design pressure of the shutdown cooling piping.
Decay heat removal at reactor pressures above the RHR shutd.own cooling isolatio.n pressure is typically
* PBAPS UN IT 2.
a.ccompTi'shed* by condensing the steam,i.n the* main condenser.
B 3.4-39                            Revision No. 126
 
RHR Shutdown Cooling System-Cold Shutdown
* B 3.4.8
* BASE.S APPLICABILITY
{continued)
Additionally, in MODE 2 below this pressure, the OPERABILITY requirements for the Emergency Core Cooling Systems {ECCS)
(.LCD 3.5.lt "ECCS-Operating*) do not allow placing the RHR shutdown. cooling subsystem into operation.
The requirements for decay heat removal in MODE 3. below the RHR shutdown coaling i'solation pressure and in MOOE 5 are discussed in LCD 3.4.7, *Residual Heat Removal (RHR)
Shutdown Cooling System-Hot Shutdown*; LCO 3.9. 7, "Residual Heat Removal (RHR)-High Water Level*; and LC03.9.8, aResi,dUal Heat Removal (RHR)-Low Water Level."
ACTIONS            A Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Sect i'on I. 3, Comp1eti on Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables eXpressed in the Condition, discovered to be inoperable or not within limits, will not result 1n separate entry into the Condit ion. Section I. 3 als_o specifies Required Actions of the Condition continue to apply for each additional failure., with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable shutdown cooling subsystems provide appropriate compensatory measures for separate inoperable shutdown cooling
- .--- - .    -~-~-subsy-stems.---As-such--,-a--Note-has--been.-prov-'ided--that-a-1-lows------** -
separate Condition entry for each inoperable RHR shutdown cooling subsystem.
A.J.
With one of the two required RHR shutdown cooling subsystems inoperable, except as pennitted by.LCO Note Z, the remaining subsystem is capable of p.roviding the required decay heat remova1. However., the overall re 11 abfl i ty is reduced.
Therefore, an alternate IRE!thod of decay heat removal must be provided. With both required RHR shutdown cooling subsystems inoperable, an alternate method of decay heat removal' must be provided in addit'lon to that provided for the initial RHR shutdown cooling subsystem inoperability.
This re-establishes backup decay heat removal capabilities, siDJilar to the requirements of the LCO. The I hour Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat
{continued)
I      PBAPS UNIT 2                        B 3.4-40                        Revision No. O
 
RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 BASES ACTIONS        AJ. (continued) removal capabi 1 i-t1 es. Furthennore, verification of the functiqnal avail abil 1ty of these alternate method(.s) must be reconfirmed every 24 hours thereafter. This wil1 provide assurance of continued heat re~oval capability.
The requ i. red coo11 n*g capac.i ty of the a1tern ate method shou 1d be ensured by verifying (by c.alculation or demonstration) its capabtl ity to maintain or reduce temperature. Decay heat removal by alllbient losses can be considered as, or contri buUng to, the a1tern ate method capability. . Al tern ate methods that can be used include (but are not limited to) the Con_dl!nsate/Hain Steam Systems (feed and bleed) and the Reactor Water Cleanup System.
B.l and B.2 W'i th no RljlR shutdown cooling subsystem and no reci rcul at ion pwnp in operation, except as permitted by LCO Note 1, and
                - until RHR or recirculation pump operation is re-established, an alternate method of reacto.r coolant circulation must be -
placed into service. This will provi.de- the necessary circulation for monitoring coolant temperature. The I hour Comp-let-ion -+i me-4s-bacsec:t--on--the-c-eolant~i-r-c--u'.la-t4o~f--unet-"kmc---~-
and is modified such that the I hour is applicable separately for each occurrence involving a loss of coolant circulation. Furthennore, verification of the functioning of the alternate method must be reconfirmed every 12. hours thereafter.. This win provide assurance of continued temperature mo111toring capability.
Du.ring the period when the reactor coo1ant is be fog circulated by an a1te_rnate method (other than. by the requtred RHR shutdown cooling subsystem or recirculation pump), the reactor coohnt temperature and pressure must be periodically monitored to ensure proper function of the.
alternate method. The once per hour Completion Time is deemed* ~ppropriate.                                            *
(contihued)
* PBAPS UNIT .2                        B 3.4-41                            Revision No. O
 
RHR Shutdown Cooling System-Cold Shutdown 8 3.4.8 BASES  (c0ntinued)
SURVEILLANCE        SR 3.4.8.1 REQUIREMENTS This Surveillance verifies that one requi~ed RHR shutdown cooling subsyst~m or recirculation pump is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR 3.4.8.2 RHR Shutdown Cooling (SOC) System piping and components have the potential to develop voids and pockets of entrained gases.      Preventing and managing gas intrusion and accumulation ts necessary for proper operation of th~
required RHR shutdown cooling subsystems and may also prevent water hammer, pump cavitation, and pumping of nonco~densible gas into the reactor vessel.                        -
Selection of RHR Shutdown Cooling Sy.stem locations susceptible to gas accumulation is based on ,a revi.ew of system design information., including piping and
  -                          1"nstrumentati on drawings, isometric drawings, pl ant and elevation drawings, calculations and operational procedures.
*                              :rhe design review is supplemented by system walk downs to
    ~~- ~~  -- -----~~--v--a--H--uate-the- systemr1i--gh---pn11rrs--and---ruco11f1 rm-th,e*--rocatTon and orientation of important components that can become sources of gas dr could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.      Susceptible locations depend on pl ant and system configuration, such as stand-by versus operating con di ti ans ..
The RHR Shutdown Coo1 i ng Syst,em is OPERABLE when it is suffi ci entl y filled with water.        For the RHR SOC piping on the discharge side of the RHR pum~, acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume in the RHR SOC piping on the discharge side of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought wit hi r:i- the acceptance cri'teri a limits during performance Of the Surveillance, the SR is met and past system OPE:RABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RKR Shutdown Cooling System is not rendered inoperable by the accumulated gas Ci .e., the system is sufficiently filled w1th water), the Surveillance
* PBAPS UNIT 2                              B 3.4-42 (continued)
Revisidn No. 127
 
RHR Shutdown Cool, ng System-Co~ d Shutdown B 3.4.8
* BASES SURVEILLANCE REQUIREMENTS SR 3,4,8.2    (continu*ed) may be declare.ct met. Accumulated gas -should be eliminated or brought within tne acceptance criteria limits. Stnce: the RHR SOC piping on the discharge side of the pump is the same
                      ~s the Low Pressure Coolant Injection p4ping, performances of surveillances for ECCS TS may satisfy the fequirements of this surveillance. For t~e RHR SOC piping on th~
suctfon side of the RHR pump, the surveillance ts met by virtue of the performance df operating pracedu~es that ensure that the RHR SOC suction piping is adequately filled and vented. fhe performance of these manual actions ensures that the s*urvei11ance. is met.,-
RHR SOC System locations on the discharge sM.e of the RHR pump suscepti bl~ to gas actumul ati on are moni to.red and, if gas is foun,d, the gas vol .ume is compared to the *acceptarce criteria for the locatien. Susceptible locations in the same system flew path which are subject to the same gas intrusion mechanisms may be verif'ied by monitoring a representative subset of susceptible 1ocations. Monitoring may not be practical for locat~ons that are inaccessible due to rijdiological or environmental conditions. the plant cohfiguration, or personnel safety. For these locatiQns
* alternative methods (e.g., operating parameters., remote monitoring) may be used to monitor the susceptible location Monitoring is not required for susceptible locations wher*e
                ~~them-axi'mmo-~pm-e'ntla-1-aecull'fU11rte_d_giEvoic!v0l CITile-ITT!s -:tseen--~
eva,l uated and determined to not cha 11 enge sy.stem OPERABILITY. The accuracy of the method used for monitoring the s~scepttble locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.
The SR can be met by virtue of hav1ng am RHR SDC subsystem ins~rvice in accordance with operating procedures.
The SR is modified by a Note. The Note recogniz@s that the scope of the surveillance is limited to the RHR system components. The HPSW system components have been determined. to not be required to be in the scope of this surveillance due to operating experience and the design of th,e system.
The Survei 11 ance Frequency is controlled under the Survei'llance Frequenc;:y Control Pr_ogram. The Surveillance Frequency may vary by location susceptible to gas
                    *accumulation.
REFERENCES        None .
* PBAPS UN IT 2                          B 3,4-42a                    Revision No.        126
 
RCS PIT Limits 13' 3.4.9 a 3.4  REACTOR COOLANT SYSTEM (RCS)
B 3.4.9  RCS Pressure and Temperature CP/n LimitB BASES BACkGROUND        All components of the RCS are designed to withstand e.ffects of cyc;lic loads due to system pressLire and temperature c~anges. These loads are introduced by startup (heatup) and shutdown (cooldown) operatio'lls', p0wer transients., and rea*ctor tri~s. This LCO limits the .pres*sure and temperature changes during RCS heatup and co_ol down, within the design as.sumptions and the stress limits for cyclic operation, The PRESSURE ANO TEMPERATURE LIMITS REPORT (PTLR) (Ref. 10) contains P/T limit curves for heatup, caoldown, and inservice leakage and hydrostatic testing, and also limits the maximum rate of change of rea*ctor- cool ant temperature.
Tile criticality curve provi de<s limits for both heatulc) clnd criticality.
Ea.ch P/T limit curve defines an acceptab~e region for normal ope.ration. The usual u~e of the curves is operational guidance <luring he.atup or cooldown maneuvering, when pressure and temperature indic,ations are monitor"ed and torrrpareatoLlie app1fcabTe c["frve l;;o-ae-termine~that -opera-E1 on ___ _
is within the allbwable region.
The LGO establishes operating limiti that provide a margin t o b r i tt l @ fa il u re of t he re a c t,0 r ves s e l a nd pi pi ng Of the reactor coolant pre.ssure boundary (RCPB). The vessel is the component most subject to brittle failure. Therefore, the LC O l i mits apply to the v e:;; $el .
10 CFR 50, Appendlx G (Ref. 1), requires the establishment of PIT limits for material fracture toughness requirements of the RC.PB materials. Reference 1 requires an adequate margin to br-ittle failure during normal operation, abnormal operational transients, and system hydrostatic tests. It mandates tl:le use of the ASME Code, Section III, Apper:idix G (Ri:!f. 2).
The. actual shift in the.RTHor of the vessel material will be established periodically by removing and evaluating the irfadiated reactor vessel material specimens, in accordance with the UFSAR (Ref. 3) arrd Appendix H of 10 CFR 50 CRef. 4). The op@rating P/T limit curves w-rll be adjusted, as nece*ssary, bBsed on the evaluation findings and the recommendations of Refe:r.ence 5.
PBAPS UN IT 2                                B. 3 .. 4-43                              Revision No. 102
 
RCS P/T Umits 8 3.4.9
* BASES BACKGROUND (continued)
The P/1 Hm1t curves are comp,osite curves established by superimposing limits derived from stress analyses of those portions of the reactor vessel and head that are the most restri cttve. At any specific pressure, temperature, and temperature rate of change, one location within the reactor vessel will dictate the most restrictive limit. Acro.ss the span of the P/T limit curves, different locations are more restrictive, and, thus, the curves are composites of the most restrictive regions.
The heatup curve represents a different set Gf restrictions than the cooldown curve because the directions of the thermal gradients through the vessel wall are reversed. The thermal gradient reversal alters the location of the tensile stress between the outer and inner walls.
The criticality limits include the Reference 1 requirement that they be at least 40~F above the heatup curve or the cooldown curve and not lower than fi0&deg;F above the adjusted reference temperature of the reactor vessel material in the region that is controlling (reactor vessel flange region) .
The consequence of violating the LCD limits is that the RCS has been operated under conditions that can result in brittle failure_ of th~_!:_.e.9ctor PJ'~~u.re vesse1.c,_possihly___ -~--- __ _
lea~ing fo a nonisolable leak or loss of coolant accident.
In the event these limits are exceeded, an evaluation must be performed to determine the effect on the structural integrity of the RCPB components. ASME Code, Section XIj Appendix E (Ref. 6), provides a recommended methodology for evaluating an operating event that causes an excursion outside the limits.
APPLICABLE      The P/T limits are not derived from Design Basis Accident SAFETY ANALYSES iDBA) analyses. They are prescribed during normal operijtion to av.oi d encountering pressure, temperature, and temper.a tu re rate o,f change condi ti ans that might cause und.etected flaws to propagate and cause nonductile failure of the reactor pressure vesse1, a condition that is unanalyzed. Since the P/T limits are not derived from any OBA, there are no acceptance limits related to the P/T limits. Rather, the P/T limits are acceptance limits themselves since they preclude operation in aA unanalyzed condition .
* PBAPS UN IT 2                      B 3.4-44                            Revision No. 102
 
RCS PIT Limits B 3.4.9
* BASES APPUCABLE SAFETY ANALYSES RCS P/J limits satisfy Criterion 2 of the NRC Po~icy Statement.
(continued)
LCO            The elements of this LCO are:
: a. RCS piressure .and temperature are within the limits specified in the PTLR and heatup or co~ldown rates are within the limits specified in the PTLR;
: b. The temp~rature difference between the reactor vessel
                        .bottom head cool ar:it and the reactor pressure vess.el CRPV; coolant is within the limits speeifted in the PTLR during recirculation pump startup;
: c. The temperature difference between the reactor coolant in the respective reci rcul atfon l .o*op and in the rea.ctor vessel is within the limits specified 1n. the PTLR during recirculation pump startup;
: d.    *RCS pre5sure and temperature are within the critkality limits specified in th'e PTLR, prior to a C h i e Vi ng C r it i Ca l itY ; a nd
: e.      Tfie reactor-ves5lflange and the head flange                  -~-
temperatures are within the limits sp~cified in the PTLR when tensioning th reactor vessel head bolting studs.
These limits define allowable oper~ting regi0ns and permit a large number of operating cycles while also providing a wide margin to nondu.ctile failure.
The rate of change of temperature limits controls the thermal gradient through the vessel wall and is used as input for calculating the heatup, cooldown, and inservtce leakage and hydrostatic testing PIT limit curves. Thus, the LCO for the rate of ch.ange of temperature restricts stre5ses
                  .caused by thermal gradients and also en.s.ures the va'lidity of the P/T limit curves.
I  PBAPS UN IT 2                              B 3.4-45                    Revision No. 102
 
RCS PIT Limits B 3.4.9 BASE$
LCO          Violation of the limits places the reactor vessel outside of (continued) the bounds of the stress analyses and can increase stresses in other RCS components. The consequences depend on several fact0rs, as fol lows:
: a. The severity of the departure from the allowable operating pressure temperature regime or the severity of the rate of change of temperature,;
: b. The length of time the limits were violated (longer violations allow the teITTperature gradient in the thick vessel wal1s to beome more pronounced); and
: c. The existeaces, sizes, and orientations of flaws in the vessel materi.al.
APPLICABILITY The potential for violating a P/T limit exists at all times.
For ex,ample, P/T limit violations could result from, ambient temperature ,conditions that result in the reactor vessel metal temper.ature being less than the m.fnirnum allowed temperaturefor boltup. Therefore, this LCO is applicable even wh~n fuel is not loaded in the Core.
Operation outside the PIT limits in the PTLR while in MODES 1, 2, and 3 must be corrected sci that the RCPB is returned to a con di t1 on that has been verified by stre.ss analyses.
The 30 minute Completion Time reflects the urgency of restoring the parameters to within the analyzed range.      Most violations will not be severe, and the activity can be accomplished in this time in a controlled manner.
Besides restoring operation within limits, an evaluation is required to determine if RCS operation can continue. The evaluation must verify the RCPB fntegrity remains acceptable and must be completed if c,ontinued operation 1s desired.
Several methods may be wsed, including compari~on with pre*analyzed transients in the stress analyses, new analyses, or inspectfon of the components.
ASME Code, Section XI, Appendix E (Ref. 6), m~y be used to support the evaluation. However, its use is restricted to evaluation of the vessel beltline.
I PBAPS UN IT 2                  B 3.4-46                          Revision No. 102
 
RCS P-IT Limits B 3.4.9
* BASES ACTIONS      A,l and A.2 (continued)
The 72 hour Completion Time is reasonable to accomplish the evaluation of a mild vfolation. Mote severe violations may require special, event specific stress analyses or inspections. A favorable evaluation must be completed i_f continued operation ts desired.
Condition A is modified by a Note requ1r1ng Required Action A.2 be completed whenever the Condition is entered.
The Note emphasi,zes the- need to p*erform the eval uat, on of the effects of the excursion outside the allowable limits.
Restoration alone per Required Action A.l is insufficient because higher than analyzed stresses may have occurred and may have affected the RCPB integrity.
B.l and B.2 If a Required Action and associated Completion Time Of Condi ti on A are not met, the pl ant m1,Jst be pl aced i r'l a l ow,er MODE because either the RCS remained in an unacceptable PIT I              region for an extended period of increased stress, or a sufficiently severe event caused entry int0 an unacceptable regiort._EJ_ther possjJ?llttY indic;:9tes _a.-.-n_e_e_d_t_o_r::__mo.re _____ -~-- -
careful examination of the event, best accomplished with the RCS at .reduced pressure and temperature. With the reduced pressure and temperature conditions, the possibility of propagat1on of undetected flaws is decreased.
* Pressure and temperature are reduced by placing the plant in at least MODE 3 within 12 hours and in MGDE 4 within 36 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 wfthout challenging plant systems.
C.l and C.2 Operation outside the PIT limits in the PTLR in other than MODES 1, 2, and 3 (including defueled condttions) must be correctea so that the RCPB is returned to a c0ndition that has been verified by stress analyses, The Required Action must be initiated without delay and continued until the l imHs ar restored ..
PBAPS UN IT 2                    B 3.4-47                                  Revision No. 102
 
RCS P/T Limits B 3.4.9
* BASES ACTIONS      C.l and C.2      (continued)
Besides restoring the P/T limit parameters to within limits, an evaluation is required to* determine if RCS operation is allowed. This evaluation must verify that the RCPB integrity is acceptable and must be completed before approach~ng criticality or heating up to> 212aF. Several methods may be used, including comparison with pre-analyzed transients, new analyses, or inspection of the components.
ASME Code, Section XI, Appendix E (Ref. 6), may be used t0 suppo1rt the evaluation; however, its use is restricted to evaluat1on of the beltline, SURVEI LLANGE SR 3.4.9.1 REQUIREMENTS Verification that operation is within the PTLR limits is required when RCS pressure atrd temperature conditions are undergoing planned changes. Plant procedures specify the pressure and temperature monitoring points tv be used during
,              the ,performance of tM s Su rvei 11 anee. The Survei 11 a nee Frequency is controlled under the Surv~illance Frequency Control Program.
Sa rvei 11 an ce fo:r ~tup_. _c_o.oJJiowo, _or:_ j.n se.r.ll-ke--.:i-a k.age -and- - - ---- --
        -~~~ --hyd rosta t i-c  testing may be discontinued when the. criteria given in the relevant plant procedure for ending the activity* are satisfied.
This SR has been modified with a Note that requires this Surveillance to be performed only during system heatup and cooldown operations and inservice leakage and hydrostatic te~ting.
SR 3.4.9,2 A separate limit in the PTLR is used when the reactor is approaching criticality. Consequently, the RCS pressure and temperature must be verified within the appropriate limits before withdra'(ii ng control rods that wi 11 make the reactor critical .
* PBAPS UN IT 2                      B 3.4-48                                      Revision No. 102
 
RCS PIT Limits l3 3.4.9
* BASE~
S1:JRVEJ lLANCE REQUIREM&N.TS SR  3 .4 r 9.. 2 ( contir:11:1,ed)
Perfarming the Surv,etllarice within 15 minutes before contrGl rod withdrawa 1 for the purpose of a chi evi ng critka l HY provides adequate assurance that the limits wt l l not be-exceeded between the time of the Surveillance and the time of the control rod withdrawal.
SR 3,4,9.3 and SR l,4,9,4 Differential temperatures within the ,applica,ble ltrnits in the PTLR ensure that the,rmal stresses resulting from the startup of an idle recjrculation pump will not exceed design a110-..vanc.es. , Iti addition, compliance with therse limits ,
ensu~es that the assumptions of the analysirs for the startup of an idle recirculation lo_op (Ref. 9) are satisfied.
Performing the survei 11 an ce within 15 mi r:i utes before starting the idle rec1rculation pump provides ,all.equate assurance U1at the 1 imHs w97 l not be* exceeded be.tween the time of the Surveillance and the time of the idle p,ump start.                      -
An ac,eeQJabl e meanl of -.~temQn_s.:tr:atjog ...compli anee -Wi-th -the -
temperatute differential requireme~t in SR 3.4.9.4 is to compare the temperatures of the operating ~ecircuTation loop and the idle loop.
                  $R 3.4.9,.3 and SR 3.4.9.4 have been mo0ified by a Note that requ~res the Surveillance to be me~ only in MODES 1, 2, 3, and 4. lh MODE 5,, the ov,eral l stress on limiting components is lower. Therefore, 8.T limits arie not required. The Nots also states the SR is only required to be met dUring a reci rcul ati on pump startup,, si nee th,i s 1 s when the stresses occur.
SR 3,4,9.5r SR 3,4,9.6, and SR 3,4,9,7 Limits in the PTLR or;i the reactor vessel flange a'nct head f1 ange temperat1,1res a re \jene ra 1 Ty bou:nded by the other P/T limits during system heatup and cooldown. However, operations approaching MQDE 4 from MODE 5 and in MODE 4 with RC$ temperature less than or equal to certain specified values re,qui re- assurance that these temperatures meet the LCO l imi ts .
* PBAPS UNJT 2                            13: 3 .4-49                    Revision No. 102
 
RCS P/T Limits B '.3.4.9 BASES SURVEILLANCE  S:R 3.4.9.5. SR    3,4.9.6. and SR  3.4.9 . .Z (continued)
REQU IREMENiS The flange temperatures must be verified to be above the limits in the PTLR before a.nd while tens1oning the vesse1 head bolting studs to ensure that once t~e head is tensioned the limits are satisfied. When fn ~ODE 4 with RCS temperature~ 8Q&deg;F, checks of the flange temperatures are required beca~se of the reduced margin-to the limits. When in MODE 4 with RCS temperature ~ 100&deg; r, monitoring of the flange temperature is required to ensure the temperature is within the limits specified in the PTLR.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Progtafn.
SR 3.4.9.5 is modified by a Note that requires the Surveillance to be performed only when tensioning the reactor ~essel head bolting studs. SR 3.4.9.6 is modified by a Note that requires the Surveillance to be initiated after RCS temperature~ 80&deg;F in MODE 4. SR 3.4.9.7 is modified by a Note that requires the Surveillance to be initiated after RCS temperature~ l00&deg;F in MODE 4. The Notes contained in these SRs are necessary to specify when the reactor vessel flange and head flange temperatures are
    ~~--~~~_r_e~qui red_tQ_Q_e~eri fi ed, to be wit.hi.n-'the.JJmiJs_spe.cJ fj_ed_. _____ _
REFERniCES    1. 10 CFR 50, Appendix G.
* 2.. ASME, Boiler ,and Pressure Ve.ssel Code, Section III, Appendix G.
: 3. UF-SAR, Section 4.2.6._and Appendix K.
: 4. 10. CFR_ !30, Appendix H.
: 5. Regulatory Guide l.~9. Revision 2, May 1988 .
* PBAPS UNIT 2                      B 3.4-50                        Revision No. 102
 
RCS PIT Limits B 3.4.9 BASES                                            ~,"'-
REFERENCES    6. ASME, Boiler and Pressure
                                      --    Vessel Code, Section XI, (continued)    Appendix E.
: 7. DELETED
: 8. DELETED
: 9. UFSAR, Section 14.5.6 .. 2.
: 10. PRESSURE AND TEMPERATURE LIM.ns REPORT.
PBAPS UNIT 2                  B 3 ,4-5J                        Revision No. 102
 
Reactor Steam Do~e Pressure B J.4.10
*            ~ 3.4 B 3.4.10 BASES REACTOR COOLANT SYST[M (RC$)
Reactbr Steam Dome Pressure BACKGROUNEJ          The reactor steam dome pressure is an assume,d value in the determination of compliance with reactor pressu,te- vessel overpressu~e protection cfiteria and is also an ~ssumed init1a1 condition of design basis accidents and transients.
APPLICABLE          The re*actor steam dome pressure of :::; 105.3 psi g is crn SAFETY AN.AL Y$ES    initial cdndition of the vessel overpressure protection analysis of Reference 1. This analysis assumes an initial maximum reactor steam dome pressure and evaluates. the resp9nse of the pressure relief system, primarily the safety/relief valves, during the limiting pressdrization transient. The determination of comp*1 i a,nce with the ove.rpre$.sure criteria is dependent on the initial reactor steam dome pressure.; therefore, the limit on this pres-sure
                                  ~nsures that the assumptions of t~e overpressure protection anelysis a~e conserved. Reference 2 along with Reference 1 assurn~s an initial reactor steam dome pressure for the,
* analysis        of design basis acddents an,d transients, used to_
__ _.- ________  , ---~--- ___~--1:l.eyfl'.Il.in.e__tJie __ l iJn:Lts__foJ'.'._ +/-u..il c1 adding_ir:i:t.Bgc.LtLC s__e.e_B,asces --~-- ~-
for LCO 3.2.2, ''MINIMUM CRITICAL l?OWER RATIO CMCPR)") and 1%'
cladding p1as,tic strain (see Bases for LCD 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)'').
Reactor steam dome pressure satisfies the requirements of Criterion 2 of the NRC Policy Statement.
LCD                The specified reactor steam dome pressure limit of
                                  ~  1053 psig ensures the plant is operated within the assumptions of the reactor overpressure protection analysis.
OpeTa.tion apov.e the limit may re,sult i.n a transient re:sp.onse more severe than analyzed.
          , APPLICABILITY        In MODES 1 and 2, the reactor steam dome pressure is required to be: less tha!l or equal to the limit. In these MODES, the reactor may be generating significant steam and the events which roay challenge the overpre-ssure limits are possiblf!.
PBAPS U,NF 2                                      B 3.4-52                                  Reyisiori No. 49
 
Reactor Steam Dome Pressure B 3.4.10
* BASES APPLICABILITY    In MODES 3,    4, and 5, the limit is not applicable because (continued)    the reactor      is shut down. In these MODES, the reactor pres s ur e i s we l l be l ow t he re qui red l i mit , and no anticipated      events will challeAge the over~ressure limits.
ACTIONS          Ll With the reactor steam dome pr~ssu~e greater than the limit, prompt action should be taken to reduce pressure to below the limit and return th,e reactor to operation within the bounds of the analyses. The 15 minute Comp1etion Time is reasonable considering the importance of maintaining the pressure within limits. This Completion Time also ensures that the probability of an accident occurring whi.le pressure is greater than the limit is minimized~
a....1 If the reactor steam dome pressure cannot be restored to within the limit within the associated Completion Time, the
                    ~lant must be brought to a MODE in which the LCO does not apply.. To achieve this status, the pl ant must be brought to          1
                -- -a.t -lea-st- MQD E- 3~wH hi n - 12* hOtl rs-;- -f tre
* a i-i-owed *co1np1 e't i off- -
Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from f~ll powef conditions in an o'rderly man~er a,nd without c*halleng'ing plant systems.
SURVEILLANCE      SR    3,4,10,1 REOU IREMENTS
                    \Jeri fi cation that reactor steam dome pres-sure 1 s ~ 1053 psi g ensures that the tnitial conditions of the reactor                              '
{)Verpressure protection analysis and design basis accidents are met. The Surveillance Freque~cy is controlled under the Surveillance Frequency Control Program.
REFERENCES        L      NEDC-33566P, "Safety Analysis Report for &:xel on Peach Bottom Atomic Power Station, Units 2 and .3, C9nstant Pressure Power Uprate," Revision 0.
: 2.      UFSAR, Chapter 14 .
* PBAPS UNIT 2                            B 3.4-53                                  Revision No. 114
 
ECCS-Operating B 3.5.1
* B 3.5 B 3.5.1 EMERGENCY CORE COOLING SYSTEMS .(ECGS), RPV WATER INVENTORY CONTRO'L cwrcj, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ECCS-Operating BASES BACKGROUND        The ECCS are designed, in conjunction with the primary and secondary containment, to limit the release of radioactive materials to the environment following a loss of coolant accident ( LOCA) . The ECCS uses two independent methods (flooding and spraying) to cool the core during a LDCA. The SCCS network consists of the High Pressure Coolant Injection (HPCI) System, the Core- Spray (CS) System, the 1ow p*ressure coolant injection (lPCI) mode of the Residual Heat Removal
( RHR) System, and the Automatic Depressuri z.ati on System (ADS). The suppress.ion pool provide.s the required source of water for the ECCS. Although no credit is taken in the safety analyses for t~e condensate storage tank (CST) 1 it is capable of providing a source of water for the HPCI and CS systems.
On receipt of an initiation signal, ECCS pumps automatically start; simultaneously, the system aligns and the pumps inject water, taken either from the CST or suppression pool,
* into the Reactor Coolant System (RCS) as RCS Q.re_s_sJJL~_js_ ________ _
------~~--~ -----------oveT-c-dm~-urthe c!Tsch-arge pressureof-the ECCS pumps.
Although the system is initiated, ADS action fs delayed, allowing +/-he operator to interrupt the timed sequence if the system is not needed. The HPCI pump discharge pressure almost immediate1y exceeds that of the RCS, and the pump injects coolant into the vesse~ to cool the core. If the break is small, the HPCI System.will maintain coolant inventory as well as vessel level while the RCS is sti 11 pressurtzed. If HPCI fails, it is backed up by ADS in combination with LPCI and CS. In this event, the ADS timed sequerice would be allowed t_o time out and qpen lhe selected safety/relief Valves CS/RVs) depressurizing the RCS, thus allowing the LPCI and CS to overcome RCS pressure and inject coolant into the v~ssel. If the br~ak 1s large, RCS pressure initiaJ 1Y drops rapidly and the LPCI arid CS. cool the ~ore.
Water from the break returns to the suppression pool where it is used again and again. Water in the suppression pool is circulated through an RHR System heat exchanger cooled by the High Pressure Service Water System. Depending on the location and size of the break, portions of the ECCS may be
* PBAPS UNIT 2                          B 3.5-l                    Revision No. 145
 
ECCS-Operating B 3.5.1 BASES BACKGROUND    ineffective; however,.the overall design is effective in (continued} cooling the core regardless of the size or location of the piping break.
All ECCS subsystems are desi.gned to ensure that no single active component failure will prevent automatic initiation and successful operation of the minimum required ECCS equipment.
* The CS System (Ref. 1) is composed of two independent subsystems. Each subsystem consists of two SOS capacity motor driven pumps, a spray sparger above the core, and piping and valves to transfer water from the suppression pool to the sparger. The CS System, is designed to provide cooling to the reactor eore when reactor pressure 1s low.
Lipon receipt of an *initiation signal, the CS pwnps in both subsystems are automatic"lly started (if offsite power is available, A and C pumps in approximately 13 seconds, and B and D pumps in approximately 23 seconds, and if offsite power is not avail able, all pumps 6 seconds after AC power is avail able). When the RPV pressure drops sufficiently, CS Sy.stem flow to the RPV begins. A full flow test line fs provi'ded to route water from and to the suppression pool to allow testing of the CS System without spr:aying water in the RPV.
LPCI is an independent operating mode of the RHR System.
There are two LPCI subsystems. (Ref. 2), each consisting of two motor driven pumps and piping and valves to transfer water from the suppression pool to the RPV via the corresponding recirculation loop. The two LPCI pumps and associated motor operated valves in ~ach LPCI subsystem are powered from separate 4 kV emergency buses. Both pumps in a LPCI subsystem, inject water into the reactor vessel through a common inboard injection valve and depend on the closure of the recirculation pump discharge valve following a LPCl 1.njection signal. Therefore, each LPCI subsystems' CODIIOn inboard injection valve and recirculation pump discharge valve is powered from one of the two 4 kV emergency buses ,
associated with that subsystem (norma1 source) and has the capability for automatic transfer to the second 4 kV emergency bus associated with that LPCI subsystem. The abi1 ity to provide power to the inboat'd injection valve and the t".ecirculation pump discharge valve from ejther 4 kV emergency bus associated with the LPCI subsystem ensures that the single failure of a diesel generator (DG) will not result in the failure of 'both LPCI pumps in one subsystem.
{continued}
PBAPS UNIT 2
* B 3.5-2                    Revision No. O
 
ECCS-0pera ting B 3.5.1
* BASES BACKGROUND (continued)
The two LPCI subsystems can be interconnected vi a the LPCI cross tie valve; however, tne cross tie valve is maintained closed with its power removed to prevent loss of both LPCI subsystems cfuring a L0CA. The LPCI subsystems are designed to provide core cooling at low RPV pressure. Upon receipt of an i niti ati on signal, all four LPCI pumps are automatically started (if offsite power is available, A and B pumps in.approximately 2 seconds and C and D pumps in approximately 8 seconds, and, if offsite power is not available, all pumps immediately after AC power is available). Since one DG supplies power to an RHR pump in both units, the RHR pump breakers are interlocked between units to prevent opera ti on of an RHR pump from both units on one DG and potentially overloading the affected DG. RHR System valves tn the LPCI flow path are automatically positioned to ensure the proper flow path for water from the suppression poo1 to inject into the recirculation loops.
When the R?V pressure drops sufficiently, the LPCI flow to the RPV, via the corresponding recirculation loop, begins.
The water then enters the reactor through the jet pumps.
Full flow test* lines are provided for the four lPCl pumps to route water to the suppression pool, to allow testing of the LPCI pumps without injecting water into the RPV. These test
,                          1 in es al so provide suppression pool cool i n_2 -~~2.Q_iJ.itY_,J.s. _ __
*___ --~---------~-de-sc-r+bee-i-n-t.00 -S-:-6-:-2-:-3-;-_,'RHR-Sup(fressi on Pool Cooling,"
The HPCI System (Ref. 3) consists of a steam driven turbine pump unit, piping, and valves to provide steam to the turbine. as well as piping and valves to transfer water from the suction source to the core via the feedwater system line_, where the coolant is distributed. within the RPV through the feedwater sparger. Suction piping for the system is provided from the CST and the suppression p0ol.
Pump suction for HPCI is normally aligned to the CST source to minimize injection of suppression pool water into the RPV. However, if the CST water supply is low, or if the suppression pool level is high, an automatic transfer to the suppression pool water source ensures a water supply for continuous operation of the HPCI System. The steam supply to the HPCI turbine is piped from a main steam line upstream of the associated inboard main steam isola.ti,on valve.
The HPCI System is design~d to provide core cooling for a wide range of reactor pressures (150 psfg to 1170 psig).
U'pon receipt of an initiation signg,l, the HPCI turbine stop valv,e and turbine control valve open and the turbine accelerates to a specified speed. As the HPCI flow
* PBAPS UN IT 2                      B 3.5-3                      Revision No. 110
 
ECCS-Operating B 3.5.1
* BASES BACKGROUND (continued) increases, the turbine governor valve is automatically adjusted to maintafn design flow. Exhaust steam from the HPCI turb1ne ts dtscharged to the suppression pool. A full flow test line 1s provided to route water back to the CST to allow testing of the HPCI System during normal operation without injecting water into the RPV.
The ECCS pumps are provided with mfnimum flow bypass lines, which discharge to the suppression pool. The va.lveis in these lines automatically open to ,prevent pump damage due to overheating when other discharge line valves are closed. To ensure rapid delivery of water to the RPV and to minimize water hammer effects, ijll ECCS pump discharge ljnes are filled wft,h water. The LPCI and CS System dtscharge lines are kept full of water using a nkeep fill" system. The HPCI System is normally aligned to the CST. The height of water in the CST is sufficient ta m~intain the piping full of water up to the first isolation valve. The relative height of the feedwater line conne.cti on for HPCI is such that the water 1n the feedwater ~ines keeps the remaining portion of the HPCI dilcharge line full of water. Therefore, ffPCJ does not require a "keep fill" system when aligned to the CST. A connection to the CST mafntains HPCI full when HPGI is
                      ~ligned to the torus, and the CST level is at or above
            ----- ---e-l-'V-ilt--fon-,1-4-9-'~-0-1'-(--14 '"-irbove~--tani:.-1>0etomT. ~-~- *-- -
The Nucle.ar System Pressure Relief System consists of 3 safe,ty valv,es CSVs) and 11 safety/relief valves (S/RVs).
Toe ADS (Ref. 4) consists of 5 of the 11 S/RVs. It is designed to provide depressur1zation of the RCS during a small break LOCA 1f HPCI fails or is unable. to maintain required water level in the RPV. ADS operat1on reduces the RPV pressure to within the operating pressure range of the low pressure ECCS subsystems (CS and LPCI), so that these subsystems can provide coolant inventory makeup. Each of the S/RVs used for automatic depressurization is equipped with one nitrogen accumulator and associated inlet check valves. The accumulator p,rovides the pneumatic power to actuate the valves.
APPLICABLE          The ECCS performance is evaluated for the e~tire spectrum of SAFETY ANALYSES      break sizes for a postulate.ct LOCA. The accidents for which ECCS operation is required are presented in Reference 5.
The requ1 red an.al ys.es and assumptions are defined in Reference 6. The results of these analyses are described in References 7, 14, and 15.
Ccontintced}
PBAPS UNIT 2                                        B 3.5-4                            Revision No. 147
 
ECCS-0perating B 3.5.1
* BASES APPUCABLE SAFETY ANALYSES This LCO helps to nsure tbat th-e following acceptance criteri*a for the ECCS, established by 10 GFR 50. 46 ( Ref. 8),
(continued)    will be met following a L0CA, assuming the worst case single active companent failure in the E:C1/2S:
: a. Maximum fUel e1eme.nt cladding temperature is::;; 220D&deg;F;
: b. Maximum cladding oxidation ~s::;; o.17 times tMe total cladding thickness before oxidation;
: c.  'Maxi mum hy.drogen generation from a zirconium water reaction is~ 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding surrounding the fuel , excluding the cl act.ding surrounding the plenum volume, were to react;
: d. The core is maintained i.n a coolable geometry; and
: e. AdeE:Juate long term cooling capability is rnafotained.
The lfrniting single failures are discussed in References 7, 14, and 15. The remaining, OPERABLE ECCS subsystems provide the ca*pability to adequate1y cool th.e core* and prevent e~cessive fuel d~mage.
                  ~n,etC~CS safi sry CrfferTori 3--0r the NRC }c/G cy~ Stateme-nf~- -- -
LC0              Each ECCS injectioR/spray subsystem and five ABS valves are r,equired to be OPERABLE. The ECCS injection/spray subsystems are. defi rted as the two CS subsys.tems, the two LPCT subsystems, and one HPCI system. Th~ low pressure ECCS injection/spray subsystems are defined as the two CS subsystems and the two LPCI subsystems. Management of gas voids is important to ECCS injection/spray sqbsystem 0PERABI UT{.
With less than the required number of ECCS subsystems OPERABLE, the potential exists that during a limiting design basis L0CA concurrent wHh th*e worst case sing1e failure, the. limits spe cHied in-Reference 8 could be exceeded. All 1
ECCS subsystems ml:lst ther-efore be OPERABLE tp s*ati sty the si~gle fai1ure criteriom required by Reference 8.
A LPCI subsy.stem is considered inoperable during alfgnme-nt and operatton for decay heat removal when below the actual RHR shutdown cooling isolation pressure in MOOE 3, since transferri.n:g from tne shutdown cooling mode to the LPCI mode could result in pump cavitation and voiding in the suction PBAPS UN IT 2                          B 3.5-5                    Revision No. 126
 
ECCS-Operat i ng B 3.5.1
* BASES LCD (continued) piping, resulting in the potential to damage the RHR system, including water hammer. This is necessary since the RHR System 1s required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. At these low pressures and decay heat levels, a reduced complement of ECCS subsystems should provide the required core cooling, thereby allowing operation of RHR shutdown cooling when necessary. One LPCI subsystem shall be dec1ared inoperable when M0-34A(B) and M0-39A(B) are simuHaneo.usly open in th-e sam-e subsystem (one or both subsystems) with no Emergency Diese1 Generators (EDGs) declared inoperable to ensure compliance to References 7, 14, and 15 single failure analyses (Ref. 11).
If the M0-34A a.nd M0-39A are simuHaneousl_y open, the 'A'
                  ,subsystem of LPCI shall be declared inoperable unless the E-1, E-2, or E-4 EDG is declared inoperable. If the M0-34B and M0-39S are s.imultaneo,usly open, the 'B' subsystem of LPCI shall be declared inoperable unless the E-1, E-2, or E-3 EOG is declared inoperable.
APPLICABILITY    AH ECCS subsystems a.re required to be OPERABLE during MODES 1, 2, and 3, when there is considerable energy f~ the reactor core and core cooling would be required to prevent fuel damage in the event of a break in the primary system piping. In MODES 2 and 3, when rea~tor steam dome pressure
_i s_s__ 1-5()._ps i g..,--tlPG--I--i-s- not-~reqtri-red--to bl~-o PE1t1..-S LE~e-ca use------ - ----
the low pressure ECCS su~systems can provide sufficient flow below this pressure. In MODES 2 and 3, when reactor steam dome pressure is~ 100 p~ig, ADS is not required to be OPERABLE because the lo.w pressure ECCS subsystems can provide ~ufficient flow be1ow this pressure. Requirements for MODES 4 and 5 are specified in LCO 3.5.4, "RPV WATER INVENTORY CONTROL.            !I ACTIONS          A Note prohibits the application of LCO 3.0.4.b to an inoperable HPCI subsystem. There is an increased risk associ~ted with entering a MODE or other specified condition 1n the Applicability with an inoperable HPCI subsystem and the provisions of LCD 3.0.4.b, which allow. entry into a MODE or other s:pecifi ed cor:iditi on in the Appl i cabn ity with the LCD not met after performance of a risk assessment addressing inoperable systems and tomponents, should not b~
appl1ed in this circumstance .
* PBAPS UNIT 2                                  B 3.5-6                              Revision NG. 145
 
ECCS-Operat 1ng B 3.-5 .1
* BASES ACTIONS (continued)
A.J If any one low pressure EGCS injection/spray subsystem 1s ir:ioperablef or 1f one LPCI pump in each subsystem is tnoperable, all inoperable Sub~ystems must be restored to OPERABL'E status within 7 days (e.g., if one LPCI pwnp in
                -each s,ubsystem is *inoperable, b,oth must be restored wHhin 7 days). In this Condition, the remaining OPERABLE subsystems provide gdequate core cooling during a LOCA.,
* Howeve.r, *overall EC-CS reliability is reduced, because a .
single failure in one of the remaining OPERABLE subsystems, concurrent with a L0CA, may result in the ECCS not being
                *able to p,erform its i ntetlded safet_y funct1 on. The 7 day Completion Time is based on a reliability study (Ref. 9) that evaluated the ;:mp.act on ECCS availability, a.ssumHlg 1,1arious components and subs,ystems we,re taken out of service, The re s-u 1t s we re us e d t d ca l c ul a t e t he ave r ag,e av a i 1ab i l i t y of ECCS equipment needed to mitigate the consequences of a LOCA as a functian of allowed outage times (i.e., Completion Times) .
* PBAPS UNIT 2                        B 3.5,6a                                Reyision N*o. 96
 
ECCS-Operat1ng B 3.5.1
* BASES ACTIONS
( coht 1nued ).
Ll If the inoperable low pressure ECCS subsystem cannot be restored to OPERABLE status w1th1n the assoc1ated Complet1on Time, the plant must be ~rought to a MODE in which overall plant risk is m1nimized. To achieve this status, the plant must be brought to at least MODE 3 with1n 12 hours.
Remaining 1n the Applicability of the LCO is acceptable because the plant r1sk in K0DE 3 is stmilar to or lower thah the risk in MODE 4 (Ref. 12) and because the time spent 1n MODE 3 to perform the neces.sary repairs to r-e*store the system to OPERABLE status w111 be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk st~te. The allowed Completion Ttme is reasonable, based on operating experience, to reach the required plant conditi1Gns. from fUll power condit1ons in an orderly manner and without challenging plant systems.
C.1 and C,2 If the HPCI System is inoperable and the RCIC System is immediately verified to be OPERABLE~ the HPCI System must be
* restored to OPERABLE status within 14 days. In this Cond1tion, adequate core cooling is eITTsured by the OPERABILITY of the redundant and diverse low pressure ECCS
-----~-~--- ------- ------.*-nje*cti'on1s*p*r-ars1drsystemrlrr-co1fjWction*w1--rh-ADS :---A1so-~----- *--
the RCIC System will automatically provide ma.keup w,ater at most reactor operating pre*ssures. Immediate verification of RCIC OPERABILITY is therefore requ1red when HPCI is inoperable. This may be, performed as an administrative check by exam1nin~ logs or other information to determine if RCIC is ,out of service for maintenance or other reasons. It does not mean to perf~rm the Surveillances needed to_
demonstrate the OPERABILITY of the RCIC System. If the OPERABILITY Of the RCIC System cannot be verified immediately, however, Condition G must be immediately entered._ If a single active component fails concurrent with a design basis L0CA, there is a potential, depending on the specific failure, that the m'inimum required ECCS equipment will not be available. A 14 day Complet1on Time 1s based on a rel1.ability study ctted in Reference 9 a.nd. has been found to be acceptable through operating experience.
D.1 and 0.2 If any one low pressure ECCS injection/spray subsystem is inoperable in addition to an inoperable HPCI System, the inoperable low pressure ECCS inject1on/spray subsystem or the HPCI System must be restored to OPERABLE status withfn 72 hours. In this Condition, adequate core cooling is PBAPS UNIT 2                            B 3.5-7                        Revisfon No. 8~
 
ECCS-Operat ing B 3.5.1 BA*SES ACTIONS-        D, 1 and  D* 2 ( c-o nt i nue d )
ensured by the OPERABILITY of the ADS and the remaining low pressure ECCS subsystems. However, the overall ECCS reliability is signiflcahtly reduced because a single failure in one of the remaining OPERABLE subsystems cohcurrent with a design basis LOCA may result in the ECCS not being able to perform its intended safety function.
Since both a high pressure system (HPCI) and a low pressure subsystem are inoperable, ~ more restrictive Completion Time of 72 hours is required to restore either the HPCI System or the low pressure ECCS injection/spray subsystem to OPERABLE status. This Completion Time is based on a reliability study cited in Reference 9 and has been found to be acceptable through operating experience.
Ll The LCD requires five ADS valves to be OPERABLE in order to provide the ADS function (Refs. 7, 14, a~d 15), A single fa11ure in the OPERABLE ADS valves results in a reduction in depressurization capability. The 14 day Completion Time is based on a reliability study cite.ct in Reference *9 and has
  * ---------- --~-, ---i:reen-f ound -to--be,rc-ceptc:rbte-th-ruugh- oir~r-a-t il'Tg- experfer'ice.
: f. 1 and f ,.2 If any one low pressure ECCS injection/spray subsystem is inoperable in .addition to one inoperable ADS valve. adequate core cooling is ensured by the OPERABILITY of HPCI and the remaining low pressure ECCS injection/spray subsystem.
However, dverall ECCS reliability is reduced because a single active component failure concurrent with a design basis LDCA could result in the minimum required ECCS
                        *quipment not being available. Since both a high pressure system (ADS) and a low presrnre subsy.stem aTe iMperable, a more restrictive Completion Time of 72 hours is required to restore eitber the Tow pressure ECCS s~bsystem or the ADS valve to OPERABLE statu-s. This Completion Time is based on a reliability study cited in Ref~rence 9 and has been found to be acceptable through operating experience *
* PBAPS UNIT 2                            B 3.5-8                                Revision No. 101
 
ECCS~Operati ng ff3._5.1
* BASES ACTIONS
      <continued)
                  .G........l If any Required Action and assQ&#xa3;iated Completion 11me of Condition C, D, E or Fis not met, the plant must be brought to
: a. MOOE in which the overall pTa.nt risk is minimized. To ~achieve this status, the plant must be brought to at least MODE .3 within 12 hours. Remaining in the Appli.cab1lity of the LCO is acceptable because the plant risk in ~ODE l is similar to or lower than the risk in MODE 4 ( Ref. 12) and becalfse the time spent in MODE 3 to perform the necessary repairs to restore the system to. OPERABLE status wi 71 be shqrt. How~ver_, voluntary entry into MODE 4 may be made as it is &lso an acceptable l0w~
risk ~tate. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditicms from full power conditi ohs i !il 9n orderly manner and without challenging plant systems.
1-1.1 and H,2 If two or more AGS valves are inopera*b7e, t'he,re is a reduction in the depressuri tati on capability. The pl a*nt must be brought to a condition in which_ the L.CO does not apply. To achieve this
  -~----------~--status, ,!_he pl an_! __must_J~e br9J:Jght _tQ___aj:_l_E@2!JiQ_Q_E~_3 wi thi'n _11:~~~---
hours and reactor steam dome pressure reduced to~ 100 psig within 36 hburs. The allowed Completion Times are reasonable, based on operating experience, to reach t.ne required pla*nt conditions from full power conditions irr an 0rderlY manner and without challenging plant systems.
Ll When multiple ECGS subsystems are inoperable (for reasons 9ther than the second Condition of Condition A), as stated in Condition I, the plant is in a condition outside 0f the accident analyses. Therefore, LCO 3.0.3 must be entered i rnmedi atel y.
SURVEILLANCE  SR 3..5.1.1 REQUI REMEfHS The ECCS i r:ijecti on/spray subsystem fl ow path p1 p1 ng and c,omp0nents have the potential to develop voids and pockets of e.ntr.ained gases. Prevent1ng and managing gas i ntruston and accumulation is nece.ssary for proper operatio~ of the ECCS injeGtion/spray subsystems and may (continued)
PBAP~ UNIT 2                          B 3.5-9                                Revision No. 126
 
ECCS-Operati ng B 3.5.l
* BASES SURVEILLANCE REQU I REM EN TS SR  3.5.1.1    (continued) al so prevent a water hammer, pump cavi tatfon, an_d pumping of noncondensible gas into the reactor vessel.
Selection of ECCS injection/spray subsystem locations susceptible to gas accumulation is based on a review of system design information, including piping aTid imtrumentat1on dr.awH1gs, isometric dr.awings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to_validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped .or di ffi cult to
                      ~emove during system maintenance or restoration.
Susceptjble locations depend on plant and system configuration, such as stand-by versus operating conditions.
The ECCS injection/spray subsystem is OPERABLE when it is suffftiently filled with water. Acceptance criteria are establishe~ for the volume of accumulated gas at susceptible locations.      If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the vo1ume of accumulated gas at one or more
                  ---s.us-eeptib-le locati*ons exceeds-an -a-cceptance-crii:eri----a for -
gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the SR is met and past system OPERABILITY is evaluated* under the Corrective Action Program. If it is determined by subsequent evaluation that the mes injection/spray *subsystems a re not rendered 1noperable by the accumulated gas (i.e., the
                      .System is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas shouM be eliminated or brought within the acceptance criteria limits.
ECCS injection/spray subsystem locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptibl locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible <:lue to radiological Dr environmental conditions, the plant configuration, or personnel safety.      For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used
* PBAPS UN IT 2                            B 3.5-10
(,cont i nu e d )
Revision No. 127
 
ECCS-Operati ng B 3.5.1
* BASES SURVEILLANCE REQUIREMENTS SR 3.5,1,l (continued) to monitor the susceptible location.                Monitoring is not required for susceptible locations where the maximum potential accumurated gas void volume has been evaluated and determined to not cha 11 enge system OPE'RABI LITY. 1he accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval ..
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation.
SR    3.5,1.2 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper fl ow paths wi 11 exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct position prior to
                - -- -1 ocki n~r. --seali-ng*; --or- securing-:- A -valve -that recei ves--an - - -- ~~
i nit i a t i on s i gna l i s a11 owed to be i .n a non a c c'i den t po s it i on provided the valve wtll automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct posftion. This SR does not app1y to valves that cannot be inadvertently misaligned, such as check valves. For the HPCI System. this SR also includes the steam flow path for the turbine and the flow controller position.
For the RHR System, verify each RHR heat exchanger inlet flow control valve is positioned to achieve at least the minimum flow rate required by SR 3.5.1.7.
The Surveillapce Frequency is controlled under the Surveillance Frequency Control Program.
The Surveillance is modified by a Note which exempts system vent fl ow paths opened under admi ni strati Ve control. The administrative control should be procedura1ized and include stationing an individua1 who can rapidly close the system vent f1ow path if directed .
PBAPS UN IT 2                                B 3.5-lOa                        Revision No. 126
 
ECCS~Operating B 3.5.1
* BASES SURV.El LLANCE REQUIREMENTS
( cont i nued )
SR  3.5.1.3 Verification that ADS nitrogen supply heijder pressure is
                      ~  85 psig ensures adequate air pressure- for reliable ADS operation. The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The design pneumatic supply pre*ssure requirements for the accumulator are such that, following a failure of t~e pneumatic supply to the accumulatorj at least two valve actuations can occur with the drywell at 70% of design pressure (Ref. 10). The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pr~ssure ECCS. This minimum required pressure of~ 85 psig 1s provided by the.ADS instrument air .supply. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR  3.5,1.4 Verificatton that the LPCI cross tie valve is closed and power to 1ts operator is disconnected ensures that each LPU subsystem remains i t1dependent .and a failure of the fl ow path in one .subsystem wi 11 not affect the fl ow path of the other
_ _ LPCI subsystem. _As;_<::~ptabl e methods of removing power ~ ~ - - __ _
operator include de-energizing breaker control power or racking out or removing the breaker. If the LPCI cross tie valve i,s open or power has not. been removed from the valve ope.rator, b.oth LPC1 subsystems must be considered inoperable. The Surveillance Frequency is controlled under th~ Sur~eillance Frequency Control Program .
* PBAPS UN IT 2                          8 3.5-11                      Re*v i s i on No . 8 6
 
ECCS - Operating s* 3. s.1
* BASES SURVEILLANCE REQUIREMENTS SR 3',5,1.5 (continued)      Cycling the recirculation pump discharge valves- through one complete cycle of full travel demonstrates that the valves are me*chani ca 11 y OPERABLE and wi 11 close when required.
Upon i n-:i ti ation of an automatic l.PCI subsystem injection signal, these valves are required to be closed to ensure full l:.PCI subsystem-flow injecti,on in the reactor via the recirculation jet pumps. De-energizing'the valve in the closed position will also ens&#xb5;re the proper flow path for the LPCI subsystem. Acceptable* methods of de-energizing the valve include de-energizing* breaker control power, racking out the breaker or removing the breaker, If the valve is inoperable and in the open position, the associated LPCI subsystem must be declared inoperable. The Frequency of th1s SR is in accordance with the INSERVICE TESTING PROGRAM.                                -
SR 3-5,1.6 Verification of the automatic transfer between the normal and the alternate power source (4 kV emergency bus) for each
                -~ -~LPGl--subsystem-inb0ar--d =inje0-tion --valve--and -each ~--~ ~-- --~ - --~ - -
recirculation pump discharge valve demonstrates that AC electrical power will be available to operate these valves following loss of power to one of the 4 kV emergency buses.
The ability to provide power to the inboard injection va1ve and the recirculation pump discharge valve from either 4 kV emergency bus, associated with the LPG subsystem ensures that the single failure of an DG wi 11 not result in the (continued)
* PBAPS UNIT 2                            B 3.5-12                      Revision t:,lo. 140
 
ECCS-Operati ng
                                                                                          *s 3. 5 .1
* BASES SU RV EI LLANCE REQU IREHENTS SR 3 . 5, 1. 6 ( cont 1nued )
failure of both LPCI pumps in one subsystem .. Therefore, fa1l ure of the automatic transfer capabi 1ity w111 result fn the.inoperability of the affected LPCI subsystem. The Survei 11 ar:ice Frequ.ency is .control 1ed under the Surv.etl 1ance Frequ.ency Control Pro&sect;ram.
SR 3.5.1.7. SR 3.5.1.8. and SR 3.5.1.9 The performance requirements of the low pressure ECCS pumps are determined through application of the 10 CPR 50, Appendtx K criter*ia (Ref. 6). This periodic Surveillance* is performed to verffy that the. ECCS pumps wi 11 develop the flow rates required by the respective analyses. The low press*ure ECCS* pump fl ow rates ensure that ade.quate. core cooling is provided to satisfy the acceptance criteria of Reference 8. The pump fl.ow rates are verified against a s_y_stem head equ.ivalent to the RPV pressure expected during a LOCA. The total system pump outlet pressure is adequate to overcome the elevatiQn head pressure between the pump suction and the vessel discharge, th*e piping friction losses, and RPV pressure present during a LOCA. These values may be establislted-by testi*ng or analysis or during
* pre operation.al testing.. Co re s RrayJ_ldfilP~fJUJ.Lr_~ej_U _artc_e __ ~-~ -,*--
-------~-,~---~--    ~ ~  --r reqLli rements, ensur-e that the fl ow rates of Reference 7 are met. Long term core spray fl ow requirements (Ref. 13) are assured by the existence of high pump run out flow capability. SR 3.5.1.7 also accounts for any pip4ng leakage in the system.
To avoid damaging CS System valves during testing, throttling is not normally performed to obtain a system head corresponding to a reactor pressure o,f ~ 105 psig. As such, SR 3,5.1.7 is modified by a Note to allow use of pump curves to determine equfvalent values for flow rate and test p:ressure for the CS pumps in ord.er to meet the Survei 11 ance Requtrement. The Note allows baseline testing at a system head corresponding to a reactor pressure of~ 105 pstg to be used to determine an equivalent flow value at ttie normal test pressure. This baseline testing is performed after any modification or repair that could affect system flow characterist1cs.
The f7ow tests for the HPCJ System are performed at two different pressure ranges sucb thijt system capability to provide rated flow is tested at both the higher and lower operating ranges of the system. Additionally, adeqQate steam flow must be passing through tlie main turbine or turMne bypass valves to conttnue to control reactor -
PBAPS UNIT 2                              B 3.5-13                      Revision No. 99
 
ECCS-Operat i ng B 3.5.1
* BASES SURVEILLANCE REQUIREMENTS SR 3.5.1.7. SR 3.5,i,8. and SR 3.5,1,9 (continued) pressure when the HPCI System ,diverts steam fl ow. Reactor steam pressure must be~ 1053 and~ 910 psi~ to perform SR 3.5.1.8 and greater than ot equal to the Electro-Hydraulic Control {EHC) System minimum pressure set with the EHC System controlling pressure (EHC System begins controlling pressure at a nominal 150 psig) and~ 175 psig to* perform SR 3. 5 .1. 9. Adequate steam fl ow is represented by at least 2 turbine bypass valves open. Therefore, suffi-cient time is all owed after adequate pr,essure and fl ow are achieved to perform these tests. Reactor startup is allowed prior to per:forming the low pressure Surveillance test because the reactor pressure is low and the time a1-1owed to satisfactorily perform the Surveillance test is short. The reactor pressure is allowed to be increased to normal operating pressure since it 1s assumed that the low pressure test has be,en satisfactorily comp1eted and there is no indication or reason to believe that HPCI is inoperable.
Therefore, SR 3.5.1.8 and SR 3.5.1.9 are modified by Notes that state the Surveillances are not required to be performed until 12 hours after the reactor steam ~ressure and flow are adequate to ~erfcrm the test.
      ------ - - ----* -l"hrlurv-ei-1-i-cJT1ce1/2 rreqa*e-r:rcy7-S""Cofltl'omcrurfaerYhe*-
survei l lance Frequency Contro,l Program .
                        .SR 3,5,1,10 The ECCS subsystems are. required to a.ctuate automatically to perform their design functions. This Surveillance verifie~
that, with a required system initiation signal (actual o~
simulated), the automatic initiation logic of HPCI, CS, and LPCI wi 11 cause Ule systems or subsystems to operate as
                        .designed, including actuation of the sys.tern throughout its emergency operating sequence. automatic pump startup and actuation of all automatic valves to their required positions. This SR also ensures that either the HPCI System
* P'BAPS UNIT 2                                B 3.5-14                      Revision No. 143
 
EC CS- 0 pe r a t i ng B J.5.1 BASES SlJRVEILLANCE  SR  3.5,1.10  (continued)
REQU I REMl:NTS will automatically restart on an RPV low water level (Level
: 2) s1gna1 received subsequent to an RPV high water level (Level 8) trip or, if the initial RPV low water lever (Level
: 2) signal was not manually reset, then the HPCI System will restart when the R~V high water level (Level 8) trip automatically clears, and that the suction is automatically transferred from the CST to the suppressjon pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCD 3.3.5.1 overlaps this Surveillance to provide complete testing of the assumed safety function.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
This SR is modified by a Note that excludes vessel injecti~n/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance .
* SR  3,5.1.11 The ADS designated S/RVs are requireg_t,Q.._A.__ctuate - - - ~ - - - - __
automaticall~ upon receipt of specific initiation signals, A system funct1 onal test 1_s performed to demonstrate that the mechanical portions of the ADS function Ci .e.,
solenofds) operate*as designed when initiated either by ari actual or simulated initiation signal, causing proper actuation of all the required c.omponents.-._,SR,3.5.1.12 and the LOGIC SYSTEM F~NCTIO~AL TEST-performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the.
assumed safety function.
The Survei 11 ance Frequency is controlled. under the Surveill9nce Frequency Control Program .
* PBAPS UN IT 2                      B 3.5-15                      Revision No. 86
 
EC CS - O,p e r at i ng
                                                                      . B 3. 5 .1 BASES SURVEILLANCE  SR 3.5.1.11    \Continued)
REQUIREMENTS This SR is modified by a Note that ~xcludes valve actuation.
This prevents an RPV pres.sure bl owdown.
SR  ~.5.1.12 The pneumatic actuator of each ADS valve is stroked to verify that the second stage pilot disc rod is mechanically displaced w.hen the i:lctu.ator strokes. Second stage pilot rod movement is determined by the m_easurement of actuator rod travel. The total amount of movement of the second stage pilot rod from the valve closed position io the open position shall meet criteria established by the S/RV supplier. SRs 3.3.5.1.5 and 3.5.1.11 overlap this Surveillance to provide testing of the SRV depressurization mode function.
The Surveillance Frequency is contrblled under the Surveillance Frequency Control Program .
*                                                                    (Continued)
* PBAPS UN IT 2                  B 3.5-16                    Revision      No. 86
 
ECCS-Operat i ng B 3.5.1
* BASES  ( cont i hued)
REFERENCES            1. UFSAR, Section 6.4.3.
: 2. UFSAR, Section 6.4.4.
: 3. UFSAR, Section 6 .4.1.
: 4. UFSAR, Sections 4.4.5 and 6.4.2.
: 5. UPSAR, Section 14. 6.
: 6. 10 CFR 50, Appendix  K.
: 7. NEDC-32163P, ~Peach Bottom Atomic Power Station Units 2 and 3 SAFER/GESTR-LOCA Loss of Coolant Accident AnaTysis," January 1993.
: 8. 10 CFR 50.46.
: 9. Memorandum from R.L. Baer (NRC) to V. Stello, Jr.
(NRC), "Recommended Interim Revisions to LCOs for ECCS Components," December 1, 1975 .
* 12.
UFSAR, Section 10.17.6.
------ ------------ --------n-.~~1s-s0e-Reporf T8"9T67-;-ope-fa6*n-ffy m-R1lRwtiTTe *11,~*test ____ _
Modes/Torus Cooling.
NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plantsj December 2002.
: 13. GE Position Summary - Long-Term Post-LOCA Adequate Core Cooling Requtreme.nts (DRF-E22-0C135-01, Revision 0, November 2000).
: 14. G-080-VC-400, "Peach Bottom Atomic Power Station Units 2 & 3 GNF2 ECCS-LOCA Evaluation," GE Hitachi Nuclear Energy, 0000-0100-8531-Rl, March 2011.
: 15. G-080-VC-272, "Peach Bottom Atomic Power Station ECCS-LOCA Evaluation for GE14," General Electric Company, GENE-Jll~03716,09-02P, July 2'000 .
* P'BAPS UNIT 2                          B 3.5-17                  Revision No. 101
 
B 3.5.2
* B 3.5 B 3.5.2 EMERGENCY CORE COOLING SY.STEMS (ECC.S)., RP*V WATER INVENTORY CONTROL (WIC), AND REACTOR CORE ISOLATION COOLING CRC1C) SYSTEM De1eted
* PBAPS UN IT 2                        B 3. 5-18                      Revision N'o. 145
 
TECHNICAL SPECIFICATIONS BASES SECTION B 3.5.2 HAS BEEN DELETED AND PAGES B 3.5-I9a THROUGH B 3.5-23 INTENTIONALLY OMITT.ED *
* PBAPS UNIT 2                                                  Revision No. 145
 
ECCS- Shutdown; B 3.5.2 BASE,S LGO,          _ Mode 4 with RCS depressurized or Mode 5:
( conti'nued)
M0.-34A( B) and M0-3.9A(B) Cl Qsed:
When the Unit is in Mode 4 with reactor steam dome pressure i ndi cati ng that th RCS is depressurfzed or in Mode 5 AND there are no flow paths that could divert LPCI flow going to t~e reactor vessel (-i.e., M0-34/39 Clo.sect), then both subsystems Of lPCI can be considered 0perable as the required ECCS_injection/spray sub'systems.
M0-34A(B) and M0-39A(B) Open:
When 'M0-20, M0-34A, and M0-39A are simultaneously open, the 'A' subsystem of Core Spray and both .subsystems of LPCI cannot be considered as separate EGCS injection/spray subs1stems because a single failure (failure of the E-3 EOG} exists that caus~s the "A' subsystem of Core Spra.y and both subsystems of LPCI to be unable to perform their design functi ans. As a result, the I A' subsystem of Gore Sptay and both subsystems of LPCJ can or:ily be considered as one of the two required ECCS i nj ecti o!llw_r__ax__s tl.h5y...s t.ems~when~a-1-i-gn eo---m--ttrh;- -
                  -- *--configuration.
When M0-20, M0-34A, and M0~39A are simultaheot1sly open with either the E-1, 'E-2, or E-4 EDG declared fnoperable, then the 'A' and
                        'B' .subsystems of LPCI may be credited as being operable, separate subsystems, since a f'ailure of the E-J EDG ts not postulated.
When M0-20. Md-34S, and M0-398 are sfmultaneou~ly open, the 'B' subsystem of Core Spray and both s_ubsystems of LPCI c::annot be considiereci as se_parate ECCS inject1on/spray subsystems because a single failure (fatlure of E-4 EDG) exists that causes the 'B' subsystem of Core .Spray and both subsystems of LPCT to be unable to perform their design 'functions, As a result, the 'B' subsystem of Core Spray and both subsystems of lPCI can only be considered as one 0f the two required ECCS injection/spray subsystems when aligned in this conflguratioo, PBAP'S UNIT 2              B J.5-19a .                                Revision No. 96
 
ECCS-Shutdown B 3.5.2
* BASES LGO (continued)
When M0-20, M0-34B, and M0-398 are simultaneously open with either the E-1, E~2, or E-3 EOG declared inope,rable, then the 'A' ar:id
                                        'B' subsystems of LPCl may be credited as bei fig operab1e, separate subsystems, since a failure of the E-4 EDG is not postulated.
APPLICABILITY    OPERABILITY of the low pressure ECCS. injection/spray subsystems is required in MODES 4 and 5 to ensure adequate cool ant inventory and sufficient heat removal capability for the irradiated fuel in the core in case .of an inadvertent dra i ndown of the vessel. Requirements for ECCS OPERABILITY during MODES 1, 2, and 3 a.re discussed in the App]icabiltt;y section of the Bases for LCO 3.5.1. ECCS subsystems are not required to be OPERABLE during MODE 5 with the spent fuel storage pool gates removed, the water level maintained at
                          ~ 458 inches above reactor pressure vessel instrument zero (20 ft 11 irrches above the RPV flange), and no operations With a potential for draining the reactGr vessel (OPDRVs) in progress. This provides sufficient coolant inventory to allow operator action to te.rminat.e the inventory loss prior to fuel uncovery in case of an inadvertent draindown .
* The. Automatic Depressurization System is not required to be OPERABLE during MODES 4 and 5 because the RPV pressure is
-~--~---------~- ---::5;--1-00-p,s-4--g,--a-nd-t-he-G-S-S-ystem-and-the-tPrr s-ab-systerns-can--- -----
provide core cooling without ~ny depressuriz!tion of the primary system.
The High Pressure Coolant Injection System is not required to be OPERABLE during MODES 4 and 5 since the low pressure ECCS injection/spray subsystems can provide sufficient flow
* to the \(esse.l.
ACTIONS          A.1 and B.1 If any one required low pressure ECCS injection/spray subsystem is inoperable, an inoperable subsystem must be restored to OPERABLE status in 4 hours. In this Condition.
the remainfng OPERABLE subsystem can provide sufficient vessel fl oodi n,g capability to recover from an inadvertent vessel draindown. However, overall system reliability is reduced because a single failure in the remaining OPERABLE
* PBAPS UNH 2                          .B 3. 5-19b                      Revision No. 96
 
ECCS-Shutdown B 3.5.2
* BASES ACTIONS          A.I and B.l      (continued) subsystem concurrent with a vessel dra i ndown could result ln the ECCS not being able to perform its intended function~
The 4 hour Completion Time for restoring the required low pressure ECCS injection/spray subsystem to OPERABLE status is based on engineering judgment that considered the -
remaining available subsystem and the low probability of a vessel draind_own .event. -
With the inoperaDle,subsystem not restored to OPERABLE status in the required Completion Time, action must be immediately initiated to suspend OPORVs to minimize the probability of a vessel draindown and the subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.
C,1, C.2. D.1, D.2; and 0,3 With both of the require.d ECCS injection/spray subsystems inoperable, all coolant inventory makeup capability may be unavailable. Therefore, actions must inaediately be initiated to suspend OPDRVs to minimize the probability of a
* vessel draindown and the subsequent potential for fission
-----~- -----~ ~- - ----- ---1>roduct-----re1-en-e::--- Act1 ons must- continue un-iTI-OPDRVsafe----~- -
suspended. One ECCS injection/spray subsystem must also be restored to OPERABLE status within 4 hours.
If at least one low pressure ECCS injection/spray subsystem is not restored to OPERABLE status within the 4 hour Completion Titae, additional actions are requtred to miniDJize any potential fission product release to the environment.
This includes ensuring secondary containment is OPERABLE; one standby gas treatment subsystem for Unit 2 is OPERABLE; and secondary containment isolation capability (i.e., one isolation valve and associated instrU111entation are OPERABLE or other acceptable administrative controls to as'sure isolation capability) in each associated secondary containment penetration flow path not isolated that is asswned to be isolated to mitigate radioactivity releases .*
OPERABILITY may be verified by an administrative check, or by examining logs or other information, to determine whether the components are out of serv1 ce for maintenance o.r other reasons. It is not necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the components.
{continued)
PBAPS UNIT 2                              B 3.5-20                      Revision No. O'
 
ECcs-*snutdown B 3.5.2
* BASES ACTIONS        C, 1, C,2, D~l, 0.2, and D.3 (continued)
If., however, any l"equired component is inop~rable, then it must be restored to OPERABLE status. In this case, the Surveillance may need to be performed to restore the component to OPERABLE status.. Actions must continue. until all required components are OPERABLL The 4 hour Completion lime to restore at least one low pressure ECCS inJection/spray subsystem to OPERABLE status ensures that prompt action will be taken to provide the required cooling capacity or to initiate a~tions to place the plant in a condition that minimizes any potential f1 ss ion product rel ease to the envtronment.
SURVEIJLANCE    SR 3,5.2,1 and SR 3,5.2.2 REQUIREMENTS The 11i.nimum water level of 11.0 feet required for the supp.ression pool is_ periodically verified to ensure that the suppression pool will provide adequate net positive suction head (NPSH) for the CS System and LPCI subsystem pumps, reci.rculation volume, and vortex prevention. With the suppression pool water level less than the required limit, all ECCS injection/spray subsystems are inoperable unless
          - ~ -they-are-al-igned-t-o ...'an--OPERABL.&#xa3;--&#xa3;-5'.T.    ~ - - ~~---- --~
                  .When suppression pool leve.l is < 11,0 feet, the CS System is considered OPERABLE'only if it ca.n take suc:tion from the CST, and the CST water level is sufficient to provide the required NPSH for the CS pwnp. Therefore, a verification that either the .suppres-si.on pool water level is ~ 11.0 feet or that CS is altgned to take suction from the CST and the CST contains c!:: 17.3 feet of water, equivalent to
                  > 90,976 gallons of water, ensures that the CS Sy$tem can supply at least 50,000 gallons of makeup water to the RPV.
The unavailable volume of the CST for CS is at the 40,976 ga 11 on 1eve 1
* H~ever, as noted, only one .required cs .
subsystem may take credit for the CST option duri.ng OPDRVs.
During OPDRVs, the volume in the CST may not provide adequate makeup if the ~PY were completely drained.
Therefore, tmly one c*s subsystem is allowed to use the CST.
Thi S' ensures the other required ECCS .subsystem has adequate mijkeup volume.
Ccont1nued}
* PBAPS UNIT 2                        B 3.5-21                    Revision No. o
 
l:CCS ~ Shutdown B 3-. 5. 2
* BASES SURVEILLANCE REQU I REMEN'f S SR 3.5.2.1 and SR 3.5.2.2 (continued)
Th*e Surveillance Frequency* is controlled under the Surveillance Frequency Control Program.
SR 3.5,2,3, SR 3.5.2.5. and SR 3.5.2.6 The Bases provided fo~ SR 3.5.i.l, SR 3.5.1.7, and SR 3.5.1.10 are applicable to SR 3.5.2.3, SR 3.5.2.5, and SR 3.5.2.6, respectively.
SR 3.5.2.. 4 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS fl ow paths provides
                      ~ssurance that the proper flow paths wtll exist for ECCS operation. This SR does not apply to valves that are
,.                    locked, *sealed, or othrwise secured in position, .since Uese valves were verified to be in the correct position prier to locking, sealing. Qr securing. A valve that receives a.n initiation sign.al is allowed to be in a nonaccident po:;ition provided the vaJve will automatically
                    ~ ~-po.sHi on i-n~ffie proper- str6ke.ffme~.- This SR cfoes not ~            .
require any testfng or valve mariipulation; rather, it involves verification that those valves capable of potentially being m~spositioned are in the correct position.
This SR d:oes not appTy to valves that cannot be inadvertently misaligned, such as check yalves. For the RHR System, verify eacb RHR ~eat exc~anger inlet flow control valve is positioned to achieve at least the mirnimum flow rate required by SR 3.5.1.7. The Surveillance Frequency is c:,o.ntroJ led under the Surveillance Frequency ControT Program.
The Surveillance is modified by a Note whic::h exempts system vent fl ow* paths opened t.mder adrnini st.r.atl ve control. the admi ni strati ve control shoul ct be p.rocedural i led and i.r,cl uc!e stationing an individual who can rapidly elose the system vent fl ow path if directed .
* PBAPS lJN IT 2                          B 3.5-22                        Revision No. 126
 
ECCS-Shutdown B 3.5.2
* BASES
  -------------------~-------~-----
REFERENCES  1. NED0-20566A, "General Electric Company Analytic~l Model for Loss-of-Coolant Accident Analysis in Accordance with 10 CFR 50 Appendix K," Septembe.r 1986 .
* PBAPS UN IT 2                B 3.5-23                    Revis.ion No .. 57
 
RCIC System
                                                                                      .B 3. 5.. 3
* B 3 .. 5 B 3.5.3 EMERGENCY CORE COOLING SYSTEMS ( ECCS), RPV WATER INVENTORY CONTROL CWIC), AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM RCIC System l
BASES BAC~GROUND          The RCIC System is not part of the ECCS; however, the RC.IC System is included with the ECCS section because of their similar fun~tions.
The RCIC System is designed to op,erate either automatically or marrual l y following reactor pressure vessel ( RPV) isolation actompanied by a loss of coo7ant flow from the feedwater system to provtde ad~quate core cooling and control of the RPV water level,. Under these conditions, the High Pressure Coolant Injection (HPCI) and RCIC systems perform simtlar fuhctions, The ~CIC System design requirements ensure that the criteria of Reference 1 are satisfied.
The RCIC System (Ref. 2) consists of a st~am driven turbine pump unit, piping, and valves to provide steam t.o the tur'bi ne, as well as pi ping pnd val ve.s to transfe,r water from the suction source to the core via the feedwater sy$tem 1 foe, where the cool ant is di s.triQJJJ~eJ:LwHbiube---RPJJ_______._.
            ~~~~througn the feedwater sparger. Suction piping is provided from the condensate storage tank (CST) and the suppression pool. Pump* suction is norma1ly aligned t,o the CST to mini mi Z_e* injection of suppression pool' water into the RPV.
How,eveT, if the CST' water s.upply is low, an automatic transfer to the suppression pool water source ensures a water supp Ty fl:lr continuous operation of the RCIC System.
The steam supply to the turbine *is piped from a main ,steam line upstream of the associated inboard main steam line isolation valve.
The RCIC System is designed to provide core cooling for a wide range of reactor pressures (150 psig to 1170 psig).
Upon receipt of an tnitiation signal, the RCIC turbine accelerates, to a sp.ecified speed. As the RCIC flow increases, the turbine governor valve is automatically adjusted to maintain design flow. Exhaust steam from the RCIC turbine 1s discharged to the suppre-ssion pool. A furl flow test line is provided to royte ~ater back to the CST to allow testing of the RCIC System during normal operation without injecting water fnto the RPV ..
* PBAPS UN IT. 2                                                            Revision No. 145
 
RCIC System B 3.5.3
* BASES BACKGROUND (continued)
The RCIC pump is provide.ct with a minimum flow bypass line, which discharges to the suppression pool. The valve in this line automatically opens when the discharge line valves are c1osed. To ensure rapid delivery of water to the RPV and to minimize water hammer effects1 the RCIC System discharge piping is kept full of water. The RCIC System is normally aligned to the CST. The height of water in the CST is sufficient to maintain the piping full of water up to the first isolation va1ve. The relative height of the feedwater line connection for RCIC is such that the water in the feedw.ater 1 in.es keeps the rernaln,,ng portion of the RCIC discharge line full of water. Therefore, RCIC does not require a "keep fill" system.
APPL I CABLE        The function of the RCIC System is to respond to transient SAFETY ANALYSES    events by pNividing makeup coolant to the reactor. The RCIC System is not an Engineered Safeguard System and no credit is taken in the safety analyses for RCIC System operation.
Based on its contribution to the reduction of overall plant risk, however, the system satisfies Criterion 4 of the NRC Policy Statement .
* LCO            ----!he~Q~_EBAilJUT'L ot t_be RClC Sy_stem__pr-0v~--0es-a0-quat--e- core*- - -
cooli~g such that actuation of any of the low pressure ECCS subsystems is not required in the event of RPV isolation accompanied by a loss of feedwater flow. The RCIC System has suffici,e.nt capacity for maintaining RPV inventory during an isolat1on event. Management of gas voids is important to RCIC System OPERABILITY.
APPLICABILITY        The RCIC System is required to be OPERABLE durfng MQDE 1, and MODES 2 and 3 with reactor steam dome pressure
                      > 150 psig, since RCIC is the primary noa-ECCS water source for core cooling when the reactor is isolate,d and pressurized. In MODES 2. and 3 with reactor steam dome pressures 150 psig. In MODES 4 and 5, RCIC is not required to be OPERABLE since RPV inventory control is required by LC O 3 . 5
* 4 , " RP V Wat e r Level I nvent o r y Cont r o1 . "
(contintJed)
* PBAPS UNIT 2                                  B 3.5-25                          Revision No. 145
 
RCIC System B 3.5.3
* BASES  (continued)
ACTIONS            A Note prohibits the application of LCD 3.0.4.b to an inoperable RCIC system. There is an increased risk associated with enteri~g a MODE or other specified condition in the Applicability w1th an inoperable RCIC system and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after perform~nce of a risk assessment addressifig inoperable systems and components, should not be applied in this circumstance.
A,l and A.2 If the RCIC System is inoperable during MODE 1, or MODE 2 or 3 with reactor steam dome pressure> 150 psig, and the HPCI System ts immediately verified to be OPERABLE~ the RGIC System must be restored to OPERABLE status within 14 days.
In this Condition, loss of the RCIC System will not affect the overall pl ant capability to p,rovi de makeup i nvent9ry at high reactor pressure since the HPCI. Sy.stern is the only hig~
pressure system assumed to function during a loss of coolant accident (LOCA). OPERABILITY of HPCI is therefore immediately verified when the RCIC System is inoperable.
This may be performed as an admin1strative check, by examining logs or other information, to determine if HPCI is out of service for maintenance or othe~ reasons. It does not mean 1t is necessary to perform the Surveillances needed to dem0nstrate the OPERABILITY of the HPCI System. If the
              ------..-PEffA-lfI1---rTY_e-f _fne liP-C.T-Sy s-f.em -can noC oe -ver i flea-- -- - - - -------
immediately, however, Condition B must be immediately entered. For certain transients and abnormal events with no LOCA, RCIC (cis opposed to HPCI) is the preferred source of makeup coolant because of its relativ~ly ~mall capaeity, which allows easier control of the RPV water level.
Thereforej a limited time is allowed to restore the inoperable RCIC to OPERABLE status .
The 14 day Cornpletion Time is. based on a reliability study (Ref. 3) that evaluatad the im!)act on ECCS availability, assuming various components and subsystems were taken out of service. The results were used t0 calculate the averag*e availability of ECCS equipment_ needed to mitigate th:e consequences of a LOCA as a function of allow-ed outage times (AOTs). Because of similar functions of l'IPCI and RCIC, the AOTs (i.e., Completion Tim~s) determined for HPCI are also applied to RCIC.
Ll If the RCIC System cannot be restored to OPERABLE status within the associated Completion Time, or if the HPCI System is simultaneously inoperable, the plant must be brought to a corrdition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of PBAPS UNIT 2                                  B 3. 5-2.6                            Revision No. 66
 
ROC System B 3.5.3
* BASES
:z\CTIONS          Ll (continued>
the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MOOE 3 to perform ttie necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The al.lowed Completion Tim~ is reasonable, based on operating experi en*ce., to reach the required pl ant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE        SR 3.5.3,1 REQUIREMENTS The RCIC System flowpath piping and components have the potential' to develop voids and pockets lf entrained gases.
Preventing and managing gas intrusion and accumulation is n,ecessary for proper operation of the RCIC System and may also prevent a water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.
Selection of RCIC System locations susceptible to gas
* accumulation is based on a review of system design information, including piping and instrumentation drawings,
________ ~som~trts__~!:_awj_ng~*-- pl_~n_ an9_ ~ e_yatj__Qn Arawtng_s *~i!_nd _ _ __
calcu'lat1ons. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or cou7d otherwise cause gas to be trap-ped or d-i f.fi cult to remove during system maintenance or *restoration._ Sffs*c-eptible locations depend on plant and system configurati.on, such as st and - by ve r s us ope r at i ng con di t i on s . .
Tt:ie RCIC System is OPERABLE when tt is sufficiently filled wfth water. Acceptance criteria are established for the volume of accumulated gas at susceptible lo~ations. If accumu1 ated g.as is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas ~tone or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the SR is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RCIC System is not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acGeptance criteria limits.
( cont i nue d ) .
PBAPS UNH 2                                B 3.5-27                        Revision No.        127
 
RCIC System B 3.5.3
** BASES SURVElLLANCE REQUIREMENTS SR. 3*.5.3.*1  (continued)
RGIC System locations susceptib1e to gas accumulation are monitored and, if gas is found, the ga,s volume is comparecl to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same g.as intrusion mechanisms lliay be verified by monitoring a representative subset of susceptible
* locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety.
For these locations alternative methods (e.g., operatil:lg parameters, remote monitoring) may be used to monitor the susceptible 1ocati on. Moriitori ng is not requited fo,r susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval .
* The Surveillance Frequency is controlled under the
            ----~---&#xa3;ur-V.eill ance.-~~eque.nc-}'-.-Cont.r..ol~-12.tog.ram .-. The- Surve.i ~ 1ance.
Frequency may vary by 1ocation s.usceptible to gas accumulation.
SR  3.5,3.2 Verifying the correct alignment for manual, power operated, and automati~ valves in the RCIC flow path provides assurance that the proper flow path will exist for RCIC operation. This SR does not apply to valves that are lo~ked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does ~ot require any testing or valve man,pulation; rather, it involves verificatfon that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. For the RCIC System, this SR also includes the steam flow path for the turbine and the flow controller
* PBAPS UNIT 2 positi*on .
B 3.5-27a                                Revision No. 126
 
RCIC System B 3.5.3
* BASES SURVEILLANCE REQUIREMENTS SR 3,S.3.2 (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
The Surveillance, is modified by a Note which exempts system vent f1ow paths opened under administrative coDtrol. The administrative control should be proceduralized and include stationing an individual who can rapidly close the, system vent flow path if directed.
SR 3.5,3.3 and SR 3,5.3.4 The RCTC pump flow rates ensure that the* system can maintain reactor coolant inventory during pressurized conditions with the RPV isolated. The flow tests for; the RCIC System are performed at two different pressure ranges. such that system capability to provide rated flow is tested both at the higher and lower operating ranges of the system.
Additionally, adequate steam flow must .be passing t~rough the main turbine or turbine bypass valves to continue to control reactor pressure when the RCIC System diverts steam flow. Reactor steam pressure must be ::; 1053 and ~ 910 psig      I
* to perform SR 3.5.3.3 and greater than or equal to the          .
-----~-------- - -~~Elet:'tro~ydraul~ c~Contror-CEAC)-System mi n,mum pressure~ *set~-- __ .. -
with the ~HC System controlling pressure (the EHC System
                      ~egins controlling pressure at a nominal i50 psig) and s 175 psig to perf6rm SR 3.5.3.4. Alternately, auxiliary steam can be used to perform SR 3.5.3.4. Adequate steam flow is represented by at least 2 turbine bypass valves
                    , open. Therefore, sufficient time i.s allowed after adequate pressure and flow are achieved to perform these $Rs.
Reactor startup is allowed prior to performing the low pressure Surveillance because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance is short. Alternately, the low pressure Surveillance test may be performed prior to startup using an auxiliary steam supply. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the 1ow pressure Surveillance has been satisfactorily completed and there is no indicati-011 or reason to believe that RCIC is inoperable. Therefore, these SRs are modified by Notes that state the Surveillances are not required to be performed until 12 hours after the reactor steam pressure and flow are adequate to perform the test .
* PBAPS UNIT 2                    B 3.S'-28 (continued)
Revision No., 143
 
RCIC s-ystem B 3.5.3
* BASES SURVEILLANCE            SR 3.5.3.3 and SR 3.5.3,4 (continued)
REQU IRE'.MENTS The Surveillance Frequency is corrtrolled under the Surveillance Frequency Control Program.
SR 3,5.3.5 The RCIC System is requited to actuate automatically in order to verify its design function satisfactorily. This Survei 11 am:e verifies that, with a required system initiation signal (actual or simulat~d), the automatic in1tiat1on logic of the RCIC System will cause the system to operate as designed, including actuation of the system throughout its emergency operating sequence; that is, automat1c pump startup and actuation of all automatic valves to their required positions. This test also ensures the RCIC System will automatically restart on an RPV low water
                          .level (level 2) signal received subsequent to an RPV high water 1evel ( Level 8) trip and that the suction is automatically tranSferred from the CST to the s*uppression pool on 1ow CST 1evel. The LOGIC SYSTEM FUNCTIONAL TEST
* performed in LCO 3.3.5.2 overlaps this Surveillance to provide complete testing of the assumed safety function.
            -- ---- --- - The---Su rve fi i a-rice-Trequen cy-is -- cont ro 11 ed -uriae_r_1:tle -- ---- -
Survei 11 a nee Frequency Control Program.
This SR iS modified by a Note that excludes vessel injection during the Surveillance. Sine~ all active components are testab.le_ and full flow can be demonstrated by recirculation through the test linej coolant injection into the RPV is not required during the Surveillance.
                                                                                      .... '... (continued}
* PBAPS UNIT 2                                      B 3.5-29                                Revision No. 86
 
RClC Syst~m
                                                                            &#xa3; 3.5.3
* BASES  (continued)
REFERENUS          1.
2.
UFSAR, Section 1.5.
UFSAR, Section 4.7.
: 3. Memorandum from R.L. Baer CNRCJ to V. Stello, Jr.
(NRC), "Recommend,ed I-nterim Revisions to LC0s for ECCS Corrrp_onents," December 1, 1975.
: 4. NEDC-3i2988-A, Rev'ision 2, Technjcal Jastif-fcation to Support Risk-Informed Modification to Selected Required End States for BWR Pl ants, December 2002 .
* PBAPS UN IT 2                                                    Revision No. 66
 
RPV Water Irrventory Control B 3.5.4
* B 3.5 B 3.5.4 BASES EMERGENCY CORE COOLING SYSTEMS (fCCS), RPV WATER INVENTORY CONTROL (Wit), AND REACTOR CORE ISOLATION COOLING CRCIC) SYSTEM Reactor Pres~ure Vessel (RPV) Nater Inventory Control BACKGROUND        The RPV contains penetrations below the top of the active fuel (TAF) that have the. potential to drain the r*eactor cool ant inventory to below the TAF. If the water level should drop belDw the TAF, the ability to remove decay heat is reduced,_ which could lead to e) evated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 reqai res the RPV- water level to be. above the top of the -
active irradiated fuel at all t'fmes to prevent such ele.vated cladding temperatures.
APPLICABLE.        With the unit in MODE 4 or 5, R~Y water inventory SAFETY ANALYSES    control is not required to mitigate any events or actidents evaluated in the safety ~nalyses. RPV water invento~y rnntrol is required in MOD!:S 4) and 5 to protect Safety Lirrrit 2,Ll.3 and the fuel cladding barrier to prevent the release of radioactive material.to the environment shoul~ an unexpected draining event occur.
A do ~ e nd eJL_gu iJ lo__t_iJi e_b_r_e_a LoLi..he--R.~t o ~ Goo+ a-n t- ~ ~ ~ -
- - ~ ~ ~ ~ - ~ - - - ~ - ~ s t e m CRCS) is not postulated in MODES 4 and 5 due to the reduced RCS pressure, reduced pipin,g stresses, and due.ti.le piping systems. Instead, an event is considered in which single operator error or initiating event allows draining of the.RPV ~ater inventory through a single penetration flow path with the hi.g*hest 'flow rate, or the sum of the drain rates thro&#xb5;gh multi~le penetration flow path$ susceptible to a common mode failure (e.g .. , seismic event (except when risk is assessed and managed in accordance with TS 3.0.@), :ioss of normal power. singlf= human error). It is asswmed, based on engineering judgment, that while in MODES 4 .and 5, 0-ne low pres.sure ECCS injectt.o.n/spray subsystem can maintain adequate reaLter vessel water level.
As discassed in References 1, 2, 3, 4, and 5, operating exp~rience has shown RPV water inventory to be s~gnificant to pub1ic health ahd safety. Therefore, R*PV Water Inv.entory Control satisfies CrHrion 4 of 10 CFR 50.36(c)(2)(ii).
LCD                Tfle RPV water level must be controlled in MODES 4 and 5 to ensure that if an unexp~cted draining event shoijld occur, tl:Je reactor cool ant water level remains above the top of the active i~radiated fuel as required by Safety Lfmit 2.1.1.3.
co tinu d PBAPS UNIT 2                            8  3.5-31                            Revision No. 145
 
RPV Water Inventory Control B 3.5.4 BAStS
* LCO
( Conti nuecj)
The Limiting Condition for Operation (LCD) requires the DRAIN TIME of RPV water inventory to the TAF to be~ 36 hours. A DRAIN TIM[ of 36 hours is cQllsidered reasonable to identify and i ni ti at ~ act t on to mit i gat e un exp e ct e d .d r a i nin g of reactor coolant. An event that could cause loss of RPV water 1nventory and result in the RPV water level reachi~g the TAf 1n greater than 36 hour~ does not reRresent a stgn1ficant challenge to Safety Limit 2,1.1.3 and can be managed as ~art of normal plant operat1on.
Orte low pressure [CCS inje-ction/spray subsystem is. required to be 0-PERABLE and ca,pable of being [llanLjally started* to provide defense-in,- depth should .an u.nex*pected draining event occuf. A low pres5ure ECCS injection/spray subsjstem consists of either one Core Spray (CS) subsystem or one Low Pressure Coolant Injection CLPC1) subsyst~m.
Each CS sub-system consists of one meter driven pump, piping, and valves to transfer water f~om the suppression pool 6r condensate storage t~nk (CST) to the RPV.
Each LPCI subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV. In MODES. 4 and 5, the RHR System cross tie valve is not requtred to be closed.
The LCO fs modified by a Note which allows a required LPCI subsystem to be considered OPERABLE during alignment and operation for decay heat removal if capable of being manuql ly- realigned ( remote or local.) to the. LPCI m9(:Je and
* i s not ot he rw i s e i n,o.p er ab l e .
Alignment ?.!7d opera t j_Qri__f.(2!_ @__~9-Ll~Lr._emo'{gj__JRcJJJ.Qes_wb~ri__. -~*- -
                  - -~-trre---r*e-qa,-recf7~H~ pump , s not ope ra.t ,ng or when the system 1 s realig*ned from or to the RHR shutdown coolirng mode. This allowance is necessary since the RHR Sy.stem may be required t,o operate in the shl1tcfo_wn cooling mode to remove decay neat and sen*sible. heat from the reactor. Because of the restrictions on DRAIN TIME, suff~cient time will be available following an unexpected draining event to man1..1ally align and initiate LPCJ subsystem operatiorl to maintain RPV water inventory prior reaching the TAF.                                                    -
Alignment a.nd operation of RHR Torus Cooling Mode is NOT cpr'lsi dered ope-ratfon for Decay Heat Removal as discussed above .
RHR LPCI Mode shal 1 be considered inoperable and cannot be credited as an ECCS Tratn for RPV Inientory Control as follows:
M0-34A(B> and MQ-39ACB> OPEN:
When ~0-34ACB) and M0-39ACB) are simultaneously open, the affected 1oop of LPCJ cannot be credited as an OPERABLE ECC S r r: ai n be ca us e s i ngl e fa il ure of t he as s oc i a t ed ED G ( E-3 / E-4) results in the loop* being unable to p-erform its LPCI function due to system depressurization / drai~ing.
* PBAPS UNIT 2                                    B 3.5-32                          Revis i o_n No. 145
 
RPV Water Inventory Control B 3.5.4
* BASES LCO (continued)
When M0-34A(B) and M0-39A(B) are simultaneously open, the affected loop of LPCI cannot be credited as an OPERABLE EC CS Tr a i n when t he as s ocia t e d ED G ( E-3 / E- 4 ) i s 1noperabl e because the loop is unable to perform the LPCI function due to system depressurizatton / drainiQg.
When E-1 or E-2 EOG are inoperable, the 'A' and 'B' subsystems of LPCI may be credited as being operable, separate subsystems, since failure of a second EOG is not postulated (single failure criteria exceeded).
M0-20. M0-34A(B) and MQ-39A(B) OPEN:
When M0-20, M0-34ACB) aod M0-39A(B) are simultaneously open with either ALL EDG's operable (single failure criteria in e ff e ct ) 0R the E-3 o r E- 4 ED G de c 1 a red i nope r a b1 e , t hen t he
                'A' AND 'B' loops of RHR LPCI cannot Qe credited as OPERABLE ECCS Trains because single fa1lure or inoperability of the associated EDG's (E-3 / E-4) resu1ts in both loops being unable to perform t~eir LPCI function due to system depressurization / draining.
Core Spray Injection Made shall be considered inoperable and cannot be credited as an ECCS Train for RPV Inventory Control as follows:
M0-26ACB2 OPEN:
When M0-26A(B) is open, the affected loop of Core Spray cannot be credited as an OPERABLE ECCS Train because single failure of the assocfated EOG (E-3 / E-4) results in the loop being unable to perform its RPV Injection function due to system depressurization' / draining.
When M0-26A(B) is open, the affected loop of Core Spray cannot be credited as an OPERABLE ECCS Train when the associated EOG (E-3 I E-4) is inoperable because the loop is unable to perform its RPV Injection function due to system depressurization / draining.
When E-1 or E-2 EOG are inoperable, the 'A' and 'B' subsystems of Core Spr~y may be credited as being operable, s~parate subsystems, since failure of a second EOG is not postulated (single failure criteria exceeded).
APPLICABILITY  RPV water inventory control is required in MODES 4 and 5.
Requirements on water inventory control in other MODES are containe.d in LCDs in Section 3.3, Instrumentati.on, anct other LCOs in Section 3.5, ECCS, RCIC, and RPV Water Inventory Control. RPV water inventory control is required to protect Safety Limit 2.1.1.3 which is applicable whenever irradiated fuel is in the reactor vessel .
continue PBAPS UNIT 2                        B 3.5-32a                          Revis i-0n No. 145
 
RPV Water Inventory Control B 3.5.4
* BASES
    --------------------------------~------
ACTIONS          A.land B.l If the requir,ed low. pressure ECCS injection/spray subsystem is inoperable, it must be restored to OPERABLE status within 4 hours. In this Condition, the LCD control~ on DRAIN TIME minimite the possibility that an unexpected ~raining event tould necessitate the use of the ECCS injection/spray subsystem, however the defense-in-depth provided by the ECCS injeGtion/spray subsystem ts 1ost.
The 4 hour Completion Time for restoring the required low pressure ECC_S injection/spray subsystem to OPERABLE status is_ ba sect on eng i nee ring judgment that considers the LCO controls on ORAIN TIME and the low probability of an unexpected draining event that would result in loss of- RPV water inventory.
If the inoperable ECCS inJect,on/spray subsyst.em is not restored to OPERABLE status within the required Compl eti-on Time, action must be initiated i mmedi atei y to establish a method of water inje-ction capable of operating without offsite electrical power. The method of water injection
* includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the
______ RPV. ..oL re.fuel.:i-n9- cav-Hy-shoul d an -l:lne-xpected drai ni-ng*-i?vent-occur. The method of water injection may be manually initiated ar.d may consist of o.ne or more systems or subsystems, and must be able to access w~ter inventory capable of maintaining the RPV water level above the TAF for~. 36 h{)urs. If recirculation '(Jf injected water would occur, it may be credited in determining the necessary water volume.
C.l. C,2, and C.3 With. \fhe DRAIN Tl ME less than 36 hours but greater than or equal to 8 hours, compensatory measures should be taken to ensure the ability to implement mitigating a&#xa3;tions should an unexpected dra,ning event occur. Should a draining event lower the reactor coolant level to below the TAF, there is potential for damage to the reactor fueT cladding and release of radioactive material, Additional actions are taken to ensure that radioact1ve material will be conta1ned, diluted, and processed prior to being released to the environment.
The secondary containment provides a contro11ed volume ,n which fission products can be contained, diluted, and
* processed prior to rel ease to the environment. Requi red          1 Action C.l requires verification of the capability to establish the secondary containment boundary in less than t he- DRA I N TI ME .
PBAPS UNIT 2                              B 3.~-33                        Revision No. 145
 
RPV Water Inventory Control B 3.5.4
* BASES ACTIONS (continued)
The required verification confirms actions to establish the s,econdary containment bo:undary are preplanned and necessary materials are available, The s~condary containment boundary is considered established when one Standby G~s Treat~ent (SGT) subsystem is capable of maintaining a negative pressure in the secondary containment with respect to the environment.
Verification that the secondary containment boundary can be established must be performed within 4 hours. The required verification fs an administrative activity and does not requ1re manip~lation or testing of equipment.
Secondary containment penetration flow paths form,a part of the secondary containment boundary. Required Action C.2 requires verification of the capability to isolate each secondary containment penetration flow path in less than the DRAIN TIME. The required verification confirms actions to isolate the sec0ndary contai.nment penetration flow paths are preplanned and necessary materials are available. Power operated valves are not required to receive automatic isolation signals if they can be closed manually within the required time. Verification that the secondary containment penetration flow paths tan be isolated must be perf~rmed within 4 hours. The required verification is an
* admi ni strati ve acti'vity and does not require mantpul ati on or
                        ~~-testing of eg_uipmeQ.!_. ___ ,_    __        ________ . ----. -~--- - -
  -*-- --- - ----...,~-  -
One SGT subsystem is capable of maintaining the secondary containment at a negative pressure with respect to the environment and filter gaseous releases. Required Action C.3 requires verification of the capability to place one SGT subsystem in operation in less than the DRAIN TIME. The required verification c0nfirms actions to place a SGT subsystem in operation are preplahned and necessary materials are available. Verifitat1on that a SGT subsystem can be placed in operation must be performed within 4 hours, Th~
required verification is an administrative activity and does not require manipulation or testing of equipment.
0,1, D.2, 0.3, and D.4 With the DRAIN TIME less than 8 hours, mitigating actions are implemented in cas~ an unexpected draining event should occur. Note that if the DRAIN TIME is 1ess than 1 hour, Required Action E.1 is also applicable.
Required Action 0.1 requires immediate action to establish an additional method of water injection augmenting the ECCS injection/spray subsystem required by the LCO. The additional method of water injection includes the necessary instrumentation and controls. water sources. and pumps and PBAPS UN IT 2                          B 3.5-34                    Revision No. 145
 
RPV Water Inventory Control B 3.5.4
* BAS.ES ACTIONS C continued) valves needed to add water to the RPV or-ref.ueling ca.v-ity shOJ:Jld. an unexpected draining event occur. !he No,te to Required Act i (Jn D.1_ states that either the ECCS injection/spray subsystem or the additfona1 method of water i nj.ect ion must be capable of Qpe,ra ting without offs He electrical power. The fddliional method of water injection may be manually initiated and m~y consist Qf one or more systems or subsygtem~. T~e additiona, method of water injection must be able to acces~ w-ater inventory capa.b,le of being i:njected to maintain the RPV water level above the TAF for~ 3'6 hours. The ad.ditional method of water 1njection and the- ECCS injection/spray subs.ystem may s,hare all o.r part of the same water sources. if recirculation of injected water would occur, it may be cre~ited in determining thareq  ired water volume.
Should a draining event lower the re.actor coolant le"!el to belEJw* the TAF, there is potential for damp.ge to the_ reactor fue1 cladding_ and release of radioactive material.
Addition~l actions are taken to ens~re that radioactive materi13l 'will be cootained, diluted! and* p*rocessed prior to
                    .be.i ng rel e*ased to the environment .
* The secondary containment provides a co(ltr'ol volume into which fission_p1:_9_dU.f.U _c.a~n ))e __coo,t.aioed__,_..djJu,ted,-and ~ .. ~-- -~- -
                ---proce*ss~ef,p-rior to releas.e to the env*ironment. Required Action 0.2 reqUTres that actions be immediately initiated to establ i sb the sec0ndary containment boundary. \..Jj th the secon,ctary containment bounpary established, ane SGT subsystem is capable of maintaining a negative pressure in the secondary containment with respect to the environment.
The secondary containment penetrattons form a part of the secondary containment boundary. Required Action D.3 requires that actions b.e imme.diately inidat.ed to verify that each.
se,eondary containment penetration flow path is isolated or to verify that it can be manl!ally i solqted from the control room.
Qne SGT subsystem is capable of maintaining lhe [SecondaryJ containment at a negative pressure with respect to the environment and filter gaseous releases. Required Action D.4 requires that actions be immedfately initiated to ~erify that at least one SGT sub..system is capatle of being place(! in ope r a t ion,. The re qui red ve r if k a t i on i s a n -a dmi n i s t r a t i ve activity and does not require manipulation or testing of equipment.
* PBAPS' UNIT 2 Ll If the Required Actions and associated Completfon times of Conditions C or Qare not met or 1f the DRAIN TIME is less B' 3. 5 -, 3 5 ontinu Rev i s i on No . 145
 
RPV Water Invent0ry Control B 3.5.4
* BASES ACTIONS
( cont i nu.ed) than 1 hour, actions must be initiated immediately to restore the DRAIN TIME to 2: 36 hours. In this condition, there may be fnsufficient time to respond to an unexpected draining event to prevent the RPV water inventory from reaching the TAF.
Note that Require.ct Actions 0.1, D.2, D.3, and D.4 are also applicable when DRAIN TIME is 1ess th.an 1 hour.
SURVEILLANCE:    SR 3,5.4,1 REQUIREMENTS This Surveillance verifies that the DRAIN TIME of RPV water inventory to the TAf is~ 36 hours. The period of 36 hours is considered reasonable to identify and initiate action to mitigate draining of reactor coolant. Loss of RPV water inventory that would result in the RPV water level reaching the TAF in greater than 36 hours does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of normal plant operation.
The definition of DRAI'.N TIME states that realistic cross-sectional areas and drain rates are used in the calculation.
    .                            A realistic drain rate may be determined using a single, step-wise, or integrated calculation considering the
* changing RPV wate: 1eve l _q~_ri ng .. a_Q_l"a i_niog_ gygnt c_ *.LOL.iL __ -*- --~* ~---
-- * - - -- *- -----~----~--Control Rocn~Wpenetrati on fl ow path with the Control Rod Drive Mechanism removed and not replaced with a blank flange, the realistic cross-sectional area ts based on the control rod blade seated in the control roci guide tube. If the control rod blade will be raised from the penetration to adjust or verify seating of the blade, the exposed crosssectional area of the RP'V penetration flow path is used.
The definition of DRAIN TIME excludes from the calculation those penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are locked, sealed, or otherwise secured in the closed position.
blank flanges, or other devices that prevent flow of reactor coolant through the penetration flew paths. A blank flange or other bolted device must be connected with a sufficient number of bolts to.prevent draining in the event of an Operating Basis Earthquake. Normal or expected leakage from closed systems or past isolation devices is permitted. Determination that a system is intact and closed or isolated must consider the status of branch lines and ongoing plant maintenance and testing activities .
**                                The Re,sid!'.lal Heat Removal (RHR) Shutdown Cooling System is on1y considered an intact closed system when misalignment issues (Reference 6) have been precluded by functional valve PBAPS UN IT 2                          B. 3. 5-36                        Revision No. 145
 
RPV Water Inventory Control B 3-.5.4
* BASES SURVEILLANCE RE Ql:J IREMENT S (conti.nued) interfocks or by isolation devices 1 *such that redirection of RPV water out of an RHR subsy~tem is precluded. Further, RHR Shutdown Cooling System is only considered an intact closed system if its cont~ols have not been transferred to Rembte Shutdown, which disables the interlocks and isolation si.gnals.
The exclusion of penetration flow paths from the determination of DRAIN TIME must consider the potential effects of a single operator error or initiating event on items supporting maintenance and testing (rigging, scaffolding, temporary shielding, piping plugs, snubber removal (except when risk is assessed a.nd managed in accordance with TS LCD 3.0.8), freeze seals, etc.). If failure of such items could result and would cause a draining event from a closed system or between the RPV and the 1so 1 at ion device, the penetrat i,on fl ow path may not be excluded from the DRAIN TIME calculation.
Surveillance Requirement 3.0.1 requi'res SRs to be met between perfo~mances. Therefore, any changes in plant conditions that would change the DRAIN TIME requires that a new DRAIN TIME be determined .
The Surveillance Frequency is controlled under the
                  ~~ --'------Sur-v-e-17 l~ance- Frequency, Contro-1 Pro~frarn-: --~-      -    - -- --
                                $8 3.5,4,2 and SR 3~5.4,3 The minimum water level of 11.0 ft. required for the suppress1 on pool is peri odi ca*n y verified to ensure that the s up p re s s i on po o1 wil 1 pr ovi de ade qua t e net po s i t i ve s uct i on head (NPSH) for the CS subsystem or LPCI subsystem pump, recirculation volume, and ~ortex prevention. With the suppression po.al water 1evel "Jess than the r:equi red limit required ECCS injection/spray subsystem is inoperable unless
                              -~ltgned to an OPERABLE CST.
The requirgd C~ System ls OPERABLE only if it can take suction f~om the CST, and the CST water level is s0fficient to pro vi de the required NPSH for the CS pump. therefore, a verification that either the suppression pool water level is
                                ~ 11.0 ft. or that a required CS subsystem is aligned to take suction from the CST and the CST contains~ 90,976 gallons of water~ equivalent to 17.3 ft., ensures that the CS subsystem can supply at least 50,000 gallons of makeup water to the RPV. The CS suction is uncovered at the 40,976 gallon l eve 1 .
* PBAPS UNIT 2 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
B 3.5-37 C
Revision No. 145
 
RPV Water Inventory Control B 3.5.4
* BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.5.4.4 The flow path piping has the potential to develop voids and pockets of entrairred air. Maintaining the pump discharge lines of the required ECCS injection/spray subsystems full of water ensures that the ECCS subsystem will perform properly. This may also prevent a water hammer'following an EC CS i nit i at i on 6 i gna l . On e acc e pt abre met hod of ens ur i ng that the lines are full is to vent at the high points.
The Surveillance frequency is controlled under the S1.1rvei 11 ance Frequency Control Program.
SR 3.5.4.5 Verifying the correct alignment for manual, power operated, and automatic valves in the required ECCS subsystem flow path provides assurance that the proper flow paths will be available for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipula~ion; rather, it involves verification that those valves capable of
                --potent-1 a*l;ty -be{rig-mi spos it, cmed-afe--,i-n -the-corre*ct pos-i tfon,. -
This SR does not apply to valves that cannot be inadvertently misalig~ed, such as check valves.
The Surveillance Frequency is controlled under the Surveillance Frequen~y Control Program.
SR 3, 5 .4, 6
* Verifying that the required ECCS injection/spray subsystem can be manually started and operate for at least 10 rnjnutes demonstrates that the subsystem is available to mitigate a drai ntng event. Testing the. ECCS 1njecti on/spray subsystem through the recirculation (full flow test) line is necessary to avo~d overfilling the refueling cavity. Jhe minimum operating time of 10 minutes was based on ~ngineering judgement.
The Surveillance Fre.quericy is controlled under the Surveillance Frequency Control Program.
SR 3. 5. 4. Z -
Verifying that each valve credited for automatically isolating onti n ed PBAPS UN IT 2.                            B 3.5-3B.                        Re,v i s i on No . *14 5
 
RPV Water Inventory Control B 3.5.4
* BASES SURVE'I LLANCE REQUIREMENTS (cont1nued) a penetration flow path actuates to the isolation position on an actual or simulated RPV water level iso*lation signal is required to prevent RPV water inventory from dropping below the TAF should an unexpected drairiin,g event .occur.
RHR M0-017 and M0-018
* RWCU M0-015 and M0-018 The Surveillance Frequency is control1ed under the Survei 11 ance Fraquency Control Program.
SR 3.5.4,8 The required ECCS subsystem is required to be manually actuated. This Surveillance verifies that the required CS subsystems or LPCI subsystem. (includipg the associated pump/
valve(s}) can be placed into service.
The Survetllance Frequency is controlled under the Surveillance Frequency Control Program .
* REFERENCES      l.Information Notice 84-81 "Inadvertent Reductioh in Primary Cool ant In vent or:_y _in Boj_ l in g~.t_e_r__8.e.actar..s, Du ci11 g~. --- . -
                -~~utoown ..and Startup," November 1984.
2.Information Notice &i-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August
                                                                                                      - -~
1986.
3.Generic letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(F), ri August 1992.
4.NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Iristrumentation in BWRs," May 199J.
5.Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone l," July 1994.
6.General Electric Service Information Letter No. 388, "RHR Valve Misalignment During Shutdown Cooling Operation for BWR 3/ 4 I 5 / 6 , " Feb r u.a r y 198 3 *
* PBAPS UN IT 2                            B 3.5-39                            Rev i s i on No . 14 5
 
Primary Containment B 3.6.I.l
* B 3.6 CONTAINMENT SYSTEMS B 3.6.1.1 Primary Containment BASES BACKGROUND        The function of the primary containment is to isolate and contain fission products released from the Reactor Primary System following a Design Basis Accident (OBA) and' to conffne the postulated release of radioactive m~~erial. The primary containment consists of a stee.l vessel, which surrounds the Reactor Primary System and provides an essentially leak tight barrier against an uncontrolled release of radioactive material to the environment.
Portions of the steel vessel are surrounded by reinforced concrete for shi e*1 ~i ng purposes.
The isolatfon devices for the penetrations in the primary containment boundary are a part of the containment leak tight barrier. To maintain this leak tight barrier:
: a. All penetrations required to be closed during acctdent conditions are either:
- ----------~-    ----- - - ~ - - -
1.
2.
capable of being closed by an OPERABLE automatic Containment Isolati:on
______ --- ~-----      System, or
                                                                      -~--~-~-~ -      -
closed by manual valves, blind flanges, or
                                                                                            ------.-~----
de-activated automatic valves secured in their closed positions, *except as provided in LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)";
: b. The primary containment air lock is OPERABLE,. except as provided in LCO 3.6.1.2, "Primary Containment Air Lock"; and
: c. All equipment hatches are closed.
This Specification ensures that the performance of the primary containment, in the event of a DBA 1 meets the assumptions used i.n the safety analyses of Reference 1.
SR 3.6.1.1.1 leakage rate requirements are in conformance with 10 CFR 50, Appendix J, Option B (Ref. 3), as modified by approved exemptions.
(continued)
* PBAPS UNIT 2                                  B 3.6-1                        Revision No. 2.7
 
Primary Containment B 3.6.1.1
* BASE'S (continued)
APPLICABLE SAFHY ANALYSES The safety design basis for the primary containment is that it must withstand the pressures and temperatures of the limittng OBA without exceeding the design leakage rate.
The OBA that postulates the maximum rel ease .of .~i oacti v,e material within primary containment is a LOCk.-.-*rn the analysts of -this accident, it is assumed that pri.mary containment is OPERABLE such that release of fission products to the environment is contrblled by the rate of primary containment leakage.
Analytical *methods and assumptions involving the primary cont*ainment are presented in Reference 1. The safety analyses assume a nonmechantstic fission product release following a OBA, which forms the basis for determination of offsite doses .. The fission p.roduct release is, in turn, based on an assumed leakage rate from the primary cont a i. nment. OPERABILITY of the pr-i:ma ry c-onta i nment ensures that the leakage rate assumed in the safety analyses fs not exceeded.
* The maximum allowable leakage rate for the primary containment(~) is 0.7% by weight of the containment air
* per 24 hours at the design basis LOCA maximum peak containment pTessure ( P4 ) of 49 .1 psi g. The value of Pa
            - - - --( 4-9-.l--i,"5--"i-g }- +s- co,fl s-er-v-a-t-i-v:e-W'ith*--res p*ect*--to- t tre- ;cur rent - -~--- -:---
calculated peak drywell pressure of 48.7 psig (Ref. 2).
This value df 48.7 psig includes operation with 90&deg;F Final Feedwater Temperature Reduction.
Primary containment satisfies Criterion 3 of the NRC Policy Statement.
LCO                Primary containment QPERABILIT"Y is maintained by limiting leakage to s 1.0 ~. except prior to the first startup after Rerforming a required Primary Containment Leakage Rate
                    *Tes.tj_ng Program 1eakage test. At this time,. applicable leakage limits must be met. In addition, the leakage from the drywell to the suppression chamber must be limiied to ensure the pressure suppression function is accomplished and the suppression chamber pressure does not exceed design Ti mits. Compliance with this LCO w11 l ens.ure a primary containment configuration, including equipment hatches, that is structurally so:und and that will limit leakage to those leakage rates assumed in the safety analyses.
PBAPS UNIT 2                                        B 3.6-2                                  Revision No. 114
 
Primary Contatnrnent B 3.6.1.1
* BASES LCO (continued*).
Individu.al leakage rates specified for the p'rimary containment air lock are addressed in LCO 3.6.1.2.
APP LI CAB I LlTY  In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequerites of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, primary containment is not required to .be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.
ACTIONS          A.J.
In the event primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour. The 1 hour Completion Tim~ provides a period of time to correct the problem commensurate with the importance of maintaining primary containment OPERABILITY during MO DES 1 , 2 , a nd 3 . Th i s t i me pe r i oct a l s o el7 s ur e.s t ha t t he probabiitty of an accident (requiring primary containment OP[RABILITY) occurrtng during periods where primary cont a i nm en t i s i nope r ab l e i s mi ni ma l .
- ' ' - - - -- - - - - - ------  .B.....l *- - - -          ----*----- ~-~~-~-- -- .. -----~ ____ J__ _
If primary containment carmot be restored to_OPERABLE status within the required Completion Time, the plant mu.st be:
brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 8) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may. be .ma.de _as .it..is. _a1 s.o_ an _a_ccep+/-a bl e_J ow-risk stare. The allowed Completion Time is reasonable, based on operating experience, to reach the required pl ant co.n,diti ons from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE      SR    3,6.1.1.1 REQUIREMENTS Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing ~rogram. Failure to meet air lock leakage testing (SR 3.6.1.2.1), or main steam isolation PBAPS UN.IT 2                              B 3.6-3                              Revision No. 66
 
Primary Containment B 3.6.1.l BASES SURVEILLANCE          SR  3.6,1,1,1  (continued)
REQU LREMENTS valve leakage (SR 3.6.1.3.14), does not necessarily result in a failure of this SR. The impact of the fan ure to mee.t these SRs must be evaluated a~ainst the Type A, B, and C acceptance criteria of the Prfmary Containment Leakage Rate Testing Program. Ats 1.0 La the offsite dose consequences are bounded by the assumptions of the safety analysis. The Frequency is required by the Primary Containment Leakage Rate Testing Program.
SR  3.6,1.1.2 Maintaining th:e p,ressure suppression function of primary contafoment requires limi,ting the leakage from the d.rywell to the suppression chamber. Thus, if an event were to occur that pressurized the drywell, the steam would be directed through the downcomers into the ~Uppression pool. *This SR is a leak test that confirms that the bypass area between the drywel l and the suppression chamber is less th.an or equivalent to a one-inch diameter hole (Ref. 4). This ensures ttiat the leakage paths that would bypass the suppression pool are within allowable limits.
The Surveillance Frequency is controlled under the                  I
            -- - - -- ---Sm'Ve71Tance-Tr'equ.encyCoritroT_P.rogram.- -,wo cons-ecufi vetescr---
fai lures, however, would indicate unexpected primary containme.nt degradation; in this event, as the Note indicates, a test sh,a l l be performed at a Frequenc;y of once every 12 months until two consecutive tests pass.
(continued)
* PBAPS UN IT .2                            B 3.6-4                        Revision No. 86
 
Primary C0ntainment
* BASES REFERENCES (continued)
: 1. UFSAR, Section 14.9.
B3 .. 6.l.l
: 2. NEDG-33566P, "Saf~ty Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Press.ure Power Uprate," Revision O.
: 3. 10 CFR 50, Appendix J, Option B.
: 4. Safety Evaluation by the Office of ~uclear Reactor Regulation Supportfng Amendment Nos. 127 and 13G tu Facility Op~rating License Nos. D?R-44 and DPR-56, dated februa~y 18, 1988.
: 5. NEI 94-01, Revision 3-A and 2-.A, "Irn:lustry Gu.icieline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J."
: 6. ANSI/ANS-56.8-2002, "Containment System Leakage Testing Requirements."
: 7. Deleted
: 8. NEDC-32988-A, Revision 2, Technical Justification to Support Risk- Informed. Modi fi cation to Selected Required
_ _ _ . ~---- -,---------- -- - _.. ---- - -______.f--t=l~St-at-es---fer-8-WR-,P~ an-t--s-,-Qecember~'00~-:- - - ~ - - * * - - - - ~ - -
* PBAPS UNIT 2                                              B 3.6-5                          Revtsion No. 118
 
Primary Containment Air* Lock B 3 .6. 1.2*
B 3.6 CONTAINMENT SYSTEMS B 3,6.l.2  Primary Containment Ai.r Lock BAS.ES BACKG{WUND        one double door pri111ary containment air lock has been built into the primary containment to provide personnel access to the drywell and to provide primary containment isolation during the *.process of personnel entertng and exiting the drywe 11.. The air lock is designed to with stand the same loads, temperatures, and peak design internal and external pressures as the primary containment (R~f. 1). As p*art of the primary .containrpent, the air lock limits the release of radioactive material to the environment during normal unit operation and through a range of transients and accidents up to and intluding postulated Design Basis Accidents (OBAs).
Each air lock door has been designed and tested to certify its ~bi11ty to withstand a pressure in excess of the max1mu~
expected pressure followih,g a OBA in pri11ary containment.
Each of the doo,rs contafns a gasket seal to ensur.e pressure integrity. To effect a leak. tight seal, the air lock design uses pressure seated doors (i.e., an increase in pri11ar:y containment internal pressure results in increased sealing force on each door).
* Each air lock is nominally a ri,ght circular cylinder, 12 ft in diameter, with doors at each end that are interlocked to prevent simultaneous opening.. During periods when primary containment is not required to be OPERABLE, the .air lock interlock mechanism 11ay be disabled, al'lowing both doors of an air lock to remain open for extend.ed periods when frequent p.rimary containment entry is necessary. Under some condit1ons as allowed by this lCO, the pri,mary containment may be accessed through the air lock, when the ioterloc:k mechanism has failed., by manually perfonning the interlo.ck function.
The prf~ary containment air lock forms part of the primary containment pressure boundary. As such, air lock integrity and leak tightness are essential for maintaining primary containment leakage rate to within limits 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.
(continued)
* PBAPS UNIT 2                          B 3.6-6                      Revision No. 0
 
Primary Containment Air Lock B 3.6.1.2
* BASES    (continued)
APP LI CABLE SAFETY ANALYSES The DBA that postulates the maximum release of radioactive material with.in p,rimary containment is a LOCA. In the analysis of this accident, it is assumed that primary containment is OPERABLE, such that relea~e of fission products to the environment is controlled by the rate of primary containment leakag.e. The primary containment is designed with a maximum allowable leakage rate (La) of 0.7%
by weig,ht of the containment air per 24 hours at the maximum peak containment pressure (Pal of 49.1 psig. The value of Pa (49.1 ps1g) is conservative w,th respect to the current calculated peak drywell pressure of 48.7 psig (Ref. 3).
This value of 48.7 psig includes operation with 90&deg;F Final Feedwater-Temperature Reduction. This allowable leakage rate forms the basis for the accaptance criteria imposed on the SRs associated with the air lock.
Primary containment air lock OPERABILITY is also required to minimize the amount of fission produ*ct gases that may escape primary containment throijgh the air lock and contaminate and pressurize the secondary containment.
The primary containment air lock satisfies Crite,riol1 3 of the NRC Policy Statement.
            -~-~--As--!)a-r:t-Q-f-pr...:i ma r,y. G-bA-t-a:f-Rmef\t,- the-air- Jock~ s- s.afety --- ~------
function is related to control of containment leakage rates following. a OBA. Thus, the air lock's structural integrity and leak tightness are essential to the ~uccessful mitigation of such an event.
Th e pr i ma r y con t a i nm en t a ir l oc k i .s re qui red to be QPERAB LE .*
Fo r t he a i r l oc k t o be con s i de red OPE RAB LE , t he a i r l oc k interlock mechanism must be OPERABLE. the air lock m&#xb5;st be
                      *i.n compliance with the Type Bair lock leakage test, and both a.i r lock doors must be OPERABLE. The interlock all o.ws only one air lock door to be opened at a time. This Ptovision.ensures that a gross breath of ~rimary containment does riot exist wh~i primaiy containment is required to be 0PERA BLE . Cl os ur e of a s i ngle door i n e a c h a i r l oc k i s sufficient to provide a leak tight barrier following postulated events. Nevertheless, both doo'rs are kept closed wnen the air lock is not being used for norma1 entry and exit from primary containment.
( cont foued)
PBAPS UN IT 2                                  B 3.6-7                            Revision No. 114
 
Primary Containment Air Lock B 3.6.l.2 BASES {continued)
APP LI CAB lLITY    In MODES I, 2-, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and_ consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the *primary containment air l_ock is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.
ACTIONS            The ACTIONS are modified by Note 1, which allows entry and ex.it to perfoni repairs of the. affected air lock component.
If the, outer door is inoperable, then it 111ay be easily accessed to repair. If the inner door is the one that is inoperable, however, then a short ti,me exists when the containment boundary is not intact (during access through the outer door). The ability to open the OPERABLE door, even i.f it means the primary containment boundary is temporarily not intact, is acceptable due-to the low probability of an event that could pressurize the primary containment during the short time in which the OPERABLE door is expected to be open. The OPERABLE door must be ,
inmediately closed after each entry and exit.
The ACTIONS are modified by il second Note, which ensures.
appropriate, remedial measures are taken when necessary.
- - - - - - - - - - - ----PursuanHo L--f0-3~.0;6,actions-:are-rrot-----re11utred:;---evenlf______ -~
primary contain~ent leakage is exceeding L8
* Therefore, the Note is added to require ACTIONS for .LCD 3.6.1.1, "Primary Containment,* to be taken in this event.
A.I, A.2, and A.3 With one pri111ary contaifllJlent air 1ock door inoperable, the OPERABLE door must be verified closed {Required Action A.I) in the ai.r lock. This ensures that a leak tight primary containment barrier is maintained by the use of an OPERABLE air lock door. This ac;tion must be completed within I hour.
The I hour Completion Time is consistent with the ACTIONS of LCO 3,6.1.1, which r.equires that primary containment be restored to OPERABLE status wi tM n 1 hour.
In addition, the air lock penetration must be isolated by locking closed the OPERABLE air lock door within the 24 hour Completion Time. The 24 hour Completion Time is considered rcontinuedl PBAPS UNIT 2                          B 3-.6-8                        Revision No. O J
 
Primary Cont.ainlDE!nt Air Lock B 3.6.1.2
* BASES ACTIONS            A.I, A,2, and A.3 {continued) reasonable for locking the OPERABLE air lock door, cons'idering that the OPERABLE door is being maintained closed.
* Required Action A.3 ensures that the air lock with an inoperable door has been isolated by the use of a locked closed OPERABLE air lock door. ThiS ensures that an acceptable primary containment leakage boundary is maintained. "the Completion Time of once per 31 days is based on engineering judgment and is con.sidered adequate in view of the 1ow likelihood of a locked door being mispositioned and other administrative controls. Required Action A.3 is modified by a Note that applies to air loc;:k doors located in high radiation areas or areas with li'mited access due to inerting and allows these doors to be verified locked closed *by use of adm1 ni strati ve controls. ATl owing verification by admtnistrative controls 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, ts small.
The Required Actions have been modified by two Notes.                  .
----- - - * --- - - - ~- ~ *----Note-1--en-sure-s -ttrat---<<:Jnlythe*1requirecf-ml oris incr associated* - * -*-*-*
Completion Times of Condition C are required i'f both doors in the air lock are inoperable. With both doors in the air lock inoperab~e, an OPERABLE door is not available to be closed. Required Actions C.1 and C.2 are the app.ropriate remedial actions. The exception .of Note 1 does not affect tracking the Comp.letion Time from the initial entry into Condition A; o.nly the requirement to comply with the Required Actions. Note 2 allows use of the air lock for entry and exit for 7 days under adtnini'strative controls.
Primary containment entry 11ay be requi.red to perform Technical Specffications (TS} Surveillances and Required Actions, as well as other activities on TS-required equipment or activities on equipment that support TS-required equipment. This Noteis not intended to preclude performing other activities (i.e., non-TS-related activities) if the primary containment was entered, using the inoperable air lock, to perfonn an allowed activity listed above. The administrative coh.tflols required consist of the stationing of a d~dicated individual to assure closure of the OPERABLE door except during the entry and exit, and assuring the OPERABLE door is relocked after .
* PBAPS LI.NIT 2                              B 3.6-9 (continued}
Revision No. Q
 
Primary Containment Afr Lock.
B 3.6.1.2
* BASES ACTIONS        A.I, A.2, and A,3 (continued) completion of the containment entry and ex:it. _This allowance b acceptable due to the 1ow pt'obabtl ity of an eveht that cou:ld pressurite the primary containment during the short tine that the OPERABLE door is expected to be open.
B,I, B.2, and 8,3 With an air lock interlock mechanism inoperable, the Required. AcUons and associated Comp*Tetion Times are consistent with those specified in Condition A.
The Requfred Actfons have been 110difled by two Notes.
Note l ensur~s that only the Required Actions and associated Completion Times of Condition Care required if both doors in the air lock are ino,Perable. Wi'th both doors in the air lock 'inoperable, an OPERABLE door is *not available to be closed. Required Actions C.1 and C.2 are the appropriate remedial actions. Note 2 allows *entry into and exft from the primary contai'n1119nt 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., th'e indfvidual performs the f.unct-hm--of--4-he--i-nter'l-ocki. -----~-
Required Action B.3 is modified by a Kate that applies to
                                                                            --~ -----
a'ir lock doors located in hign radiation clreas or areas with
                                                                                      ~ -
limited access due to 1nert1ng and that allows these doors to be, verified l,ocked closed by use of admtnistrative controls. Allowing verification by administrative controls is considered acc~ptab1e, since access to these areas is typically restricted. Therefore, the probability of mi sa l i gnment of the doo.r; once it has been veri f 1ed to be in the proper positton, fs small.
C,l, C.2, and C.3
* If the ai'r lock is inoperable for reasons other than those described in C'ondition A or B, Required Action C.l requires action to be iDDediately initiated to evaluate containment overa 11 leakage *rates. using current air lock leakage test results. An evaluation is acceptable si'nce it is overly conservative to 1nnediat8'ly declare the primary containment inoperable if the overall air lock leakage 1s not within CcontHtued)
PBAPS UNIT 2                        B 3 .6-10                      Revision No. O
 
Primary Containment Air Lock B 3.6.1.2
* BASES ACTIONS        C.1,  C.2, and C.3 (continued) limits. In many in.stances (e.. g., only qne sea.l per door has failed); primary-containment rematns OPERABLE, yet only 1 hour (according to LCQ 3.6.l.l), would be provided to restore the air lock door to OPERABLE status prior to requiring a plant shutdown. In addition, even with the over a11 air lock leakage not with 1n limtts, the overa 11 containment leakage rate can stfll be w.ithin li*its.
Required Action C.2 requtres that -one door in the primary cont a i n~nt air 1ock must be verified c1osed. This action.
must be completed within the I hour Completion Time. This specified tim~ period is consistent with the ACTIONS of LCO. 3. 6.. 1. 1, whi th require that primary conta foment be restored to OPERABLE statu_s within 1 hour-.
Additionally,, the air lock must be restored to OPERABLE status within 24 hours. The 24 hour Completion Time is
* reason ab 1e for restoring. an inoperable air l oc.k to OPERABLE status cons.idering that at 1east one door is maintained closed in the air lock .
P.1 and    o., Z--~~
If the tnoperable primary contair:1ment air lock cannot be restored to OPERABLE status within the associated Completion Ti.me, the plant must be brought to a MOOE in wh1 c'h the LCD does not apply. To achieve_ this status, the plant m~ust be brought to at least MOOE 3 within 12 hours and to MODE 4 within 36 hours. The allowed-Completion Tjmes are re,asonab 1e, based o.n operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE  SR 3*6. I. 2, 1 REQUIREMENTS Maintaining primary containrn.. nt air locks OPERABLE require-s com.pl iance wHh the 1eakage rate test requirements of the Pri.mary Containment Leakage Rate Testing Program., This SR reflects the 1eakage rate testing requirements with respect to air lock leakage (Type B leakage tests}. The acceptance criteria were established dari.ng inittal air lock and primary containment OPERABILITY
                                                                          <continued}
PBAPS UNIT 2                          a 3 .6-11                    Revision No. 6
 
Primary Containment A~r Lock B 3.6.1.2
* BASES SURVEILLANCE REO,U IREMENTS SR    3.6.1.2.1    (continued) testing, The periodic test,ng requirements verify that the air lock leakage does not exceed the allowed fraction of the overall primary conta-inrnent leakage rate. The Frequency is requirecl by the Primary Containment Leakage Rate Testing Program.
The SR has been modified DY two, Notes. Note l states that an inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.
Thi s i s cons i de r e.d teas on ab l e s i nce either a i r l ock door i s capable of providing a fission product barrier in the event of a DBA. Note 2 requires the results of ai r lock leakage          1 tests to be evaluated against th.e acceptance criteria of the Primary Containment Leakage Rate Testing Program, 5.5.12.
This ensures that the air lock leakage is properly accounted for in determining the combined Type Band C primary contai~ment leakage.
SR    3.6.1.2,2 The air lock interlock mechanism is designed to prevent
  ~ - - ~ - - - - - ------.SA mu.lta+l-fWUS-.opern;j tJg__c__Qf---both--dOor:'--S--:i-n-the--a-i--r-1 oG-k-.---41-nGe---- -
both the inner and outer doors of an air lock are designed to withstand t~e maximum expected post accident primary containment pressure, closure of either door will support primary contatnment OPERABILITY. Thus, the interlock feature s,u.pports primary contairiment 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 i nlerl oc:k will fun ct to.n as designed ar;id that simultaneous i:nner and outer door opening Will not inadvertently occur. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
(continued)
* PBAPS UN IT 2                                B 3.6-12                                          Revision No. 86
 
Primary Containment A1r Lock B 3.6.1.2 BASES  {co~t1nued)
REFERENCES          1. UFSAR, Section 5.2.3.4.5.
: 2. 10 CFR Sb~ Appendix J, Option B.
: 3. NEDC-33566P, "Safety Analysis Report for E.xelon Peach Bottom Atomic Power Sta ti on, Units 2 and 3 1. Constant Pressure Power Uprate," Revision 0.
: 4. Deleted PBA,PS UNIT 2                      B 3,6--13                  R~vision No. 114
 
PCIVs B 3.6.I.3
* B 3.6 CONTAINMENT SYSTEMS B 3.6.1.3 Primary Containment Isolation Valves (PCIVs)
BASES BACKGROUND      The function of- the PCIV.s, in combination with other accident mitigation systems, is to l itnit fission product release during and follQWing postulated .Design Basis Accidents (DBAs) to within l im1ts. Primary conta.inment isolation within 'the ti111e limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the .assumptions used. in the analyses for a DBA.
The OPERABILITY requirements for PCIVs help ensure that an adequate primary containment boundary is maintaineq during and after an accident by minimizing potential paths to the environment. Therefore, the O.PERABILITY requirements provide assurance that primary containment function assumed in the safety analyses will be maintained. Th_ese isolatiron devices a~e either passive or active (automatic). Closed manual valves, de-activated automatic valves secured in the.ir closed position (including check valves with flow through the valve .secured), blind flanges, and closed systems** are-constdered 1>ass ive--:devtce-s:-- -Chedc-*va-1 verand*- -- -~ * --~-
other automatic valves designed to close without operator acti*on following an accident, are considered active devices.
Two barriers in series are provided for each penetration so that no single ,credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds 1imits assumed in the .safety analyses. One of these barriers may be a closed system.
The reactor buil di ng-to-.suppressi on chamber vacuum breakers and the scram discharge volume vent and drain valves each serve a dual function, one of which is primary containment iso]ation. However, since the other safety functions of the vacuum breakers and the scram di scha.rge volume vent and drain valves would not be available if the normal PCIV actions were taken, the PCIV OPERABILITY requirements are not applicable to the reactor building-to-suppression chamber vacuUJn breaker valves and the scram discharge volume vent and drain valves. Si.milar Surveillance Requirements in the LCO for the reactor building-to-suppression chamber vacuum breakers and the LCO for the scram discharge volume (continued)
PBAPS UNIT 2                        B 3.6-14                            Revis1ron No. O
 
PCIVs B 3.6.1.3
* BASES BACKGROUND (continued) vent and drain valves provide assurance that the 1so1atton capability is available without conflicting with the vacuum relief or scram discharge volume vent and drain functions.
The primary containment purge lines are 18 inches in diameter; exhaust lines are 18 inches in diameter. In addition, a 6 inch line from the Containment Atmospheric Control (CAC} System ts also provided to purge primary containment. The 6 and 18 inch primary containment purge valves and the 18 inch primary containment exhaust valves ate nonnally maintained closed in MODES 1,. 2, and 3 to ensure the primary containment boundary is maintained.
However, containment purging with the 18 inch purge and exhaust valves 1S permitted for inert1ng, de-inerting, and pressure control. Included in the scope of the de-inerting, is the need to purge containment to ensure personnel safety during the performance of inspections beneficial to nuclear safety; e.g., inspection of primary coolant integrity during pl ant ,startups and shutdowns. Adjustments in primary ..
containment pressure to perform tests such as the drywell-to-suppression chamber bypass leakage test are included within the scope of pressure control purging. Purging for humidity and temperature control using the 18 inch valves is excluded. The isolation valves on the 18 inch vent lines
* have 2 inch bypass lines around them for use during normal
*--~ - ~~-~~~    - --.*---reactor-operaticon---when-the-18-inch-valves---cannot-be-opened-. ----
Two additional redundant Standby Gas Treatment (SGT) isolation valves are provided on the vent li.ne Upstream of the SGT .System fi.lter trains. These isolation valves, together with the PCIVs,. wn l prevent high pressure from reaching the SGT System filter t~ains in the unlikely event of a loss of coolant accident (LOCA) during venting.
The Safety Grade. Instrument Gas (SGIG) System suppl 1es pressurized nitrogen gas (from the Containment Atmosphe~ic Dilution (CAD) System liquid nitrogen storage tank) as a safety grade pneumatic source to the CAC System purge and exhaust i sol ati on valve i nfl atabl e seals, the reactor building-to-suppression chamber vacuum breaker air operated isQlation valves and inflatable seal, and the CAC and CAD Sy.stems vent *contra l air operated va 1ves. The SGIG System thus perfonns two distinct post-LOCA functions: (l) supports containment isolation and (2) supports CAD System vent operation. SGIG System requirements are addressed for
{continued}
* PBAPS *UN IT 2                        B 3.6-15                        Revision .No *. O
 
PCIVs B 3.6.1.3
* BASES BACKGROUND (continued) each of the supported system and components in LCO 3.6.1.3, "Primary Containment tsolation Valves (PCIVs)," and LCO 3.. 6.1.5, "Reactor Buildfog-to-S:uppression Chamber Vacuum Breakers." For the SGIG System, liquid nitrogen from the liquid nitrogen storage tank passes through the liquid nitrogen vaporizer where it is converted to a gas. The gas then flows into a Unit 2 header and a Unit 3 header separated by two manual globe valves. From each header, the gas then branches to each valve operator or valve s,eal supplied by the SGIG System. Each branch is separated from the heqder by a manual globe valve and a check valve.
To support SGIG System fur,cti ons, the nitrogen i n\JentorY is equivalent to a storage tank minimum required level of~ 22 inches water column, or a technically justified source of equivalent inventory~ 124,000 scf at 250 psig, and a minimum required SGIG System header pressure of 80 psfg.
APPLICABLE      The PCIVs LCO was derived from the assumptions related to SAFETY ANALYSES mi nimi zing the loss of reactor cool ant i*nventory, and establishing the primary containment boundary during major accid~nts. As part of the primary c0nta1nment boundary,
* PCIV OPERABILITY supports leak tightness of primary
_____ ----" ~ - ______contaJ.nme.nL _Thereto-re-. the--Sai-ety~na-l.y.s--:i-s-0f-an.y~e-vent--~~-~-
requi ring isolation of primary containment is applicable to this LCO.                  -
The DBAs that result in a release of radioactive material and are mitigated by PCIVs are a LOCA and a main steam lirte break (MSLB). In the analysis for each of these accidents, it is assumed that PCIVs are either c1osed or close Within the required isolation times following event initiation.
This ensures that potential paths to the environment through PCIVs (including primary containment purge valves) are minimized. Of the events analyzed in Reference 1, the LOCA i s a l i mit i ng event due to r ad i ol ogk a l con seq uen ces . Th e closure time of the main steam isolation valves (MSIVs) is the most significant variable from a radiological standpoint. The MSIVs are required to close within 3 to 5 seconds after signal generation. Likewise~ it is assumed that the primary containment is isol-0ted suc'h that release of fission products to the environment is controlled.
PBAPS UN IT 2                        6 3.6-16                          Revision No. 91
 
PCIVs B 3.6.1.3
* BASES APPLICABLE SAFETY ANALYSES The DBA analysis assumes that within 2 minutes of accident initiation, isolation of the primary containment is complete (continued)      and leakage is terminated, except for the maximum a1lowable leakage rate, la. The primary containment isolation total response time of 2 minutes includes signal delay, diesel generator startup (for loss of offsite power), and PGIV stroke times.
The single failure criterion required to be imposed 1n the conduct of unit safety analyses was considered in the original design of the primary containment purge and exhaust valves.
Two valves in series on each purge and exhaust line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred.
PCIVs satisfy Criterion 3 of the NRC Policy Statement.
Leo                p.crvs form a part of the p,imary containment boundary. The PCIV safety functi o.n is related to mi.nimi zing theo loss of the reactor coolant inventory and e~tablishing the primary containment boundary during a DBA .
* The power operated, automatic isolat~Gn valves are required to have isolation times within limits and actuate on an~~- ______ _
                  -~ automaticlsol~flons,gnal'~--Inaddi ti Qn' for the CACSystem purge and exhaust isolation valves to be considered OPERABLE, the SGIG System supplying nitrogen gas to the fnflatable seals of t"he valves must be OPERABLE. While the reactor building-to-suppression chamber vacuum breakers and the scram discharge volume-vent and drain valves isolate primary containment penetrations. they are excluded from this Specification. Contro1s on their isolation function are adequately a.ddressed in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," and LCO 3.6.1.5, "Reactor Buildfng-to-Suppression Chamber Vacuum Breakers.'' Tb*e valves covered by this LCO are listed with their associated stroke times in Reference 2. The required stroke time is the stroke time listed in Reference 2 or the Inservice resting Program which ever is more conservative.'
The normally closed PCIVs are considered OPERABLE when manual valves are closed or open *in accordance with appropriate administrative controls, automatic valves are
* PBAPS tJN IT 2                      B 3.6-17                        Rev,i s 1on No. 144-
 
PCI 1/s B 3.6.1.3
* BASES LCD (continued) d-aCtivated and secured in their closed position., blind fl ang e s a re i n p l ace , and c 1os e d s ys t ems a re i nt act . 1 hes e passive isolation valves and devices are those listed in Reference 2 and Reference 5.
MSIVs must meet additional leakage rate requirements. Other PCIV leakage rates are addressed by LCO 3.6.1.1, "Pi"imary Containment," as Type 6 or C testing..
This LCD provides assurance that the PCIVs wil1 perform their designed safety functions to minimize the )o~s of reactor coolant inventory and establish the primary containment boundary during accidents.
APPLICABI UTY In MODES 1, 2, and 3, a VBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, PClVs a re not required to be                                        l OPERABLE and the prfmary containment purge and exhaust valves are not required to be normally closed in MODES 4 and 5.
Certain valves, however, are required to be OPERABLE when the as.soci ated instrumentation ts required to be OPERABLE per LCO 3. 3. 6. 1, "Pr i mHy _c_o_l'Jta i nmerrL Ls otat i.oA -I r:is-t r{!mer,ta t-1-on ;-"- -
T(his- doesno*C;"n-clude the valves that isolate the associated instrumentation.)
ACTIONS      The ACTIONS are modified by a Note al1o.wing penetration flow path(s) except for purge or exhaust valve flow path(s) to be unisolated intermittently under administrative controls.
These controls consist of stationing a dedicated operator at the contro1s. of the va.lve, who is in continuous communication with the control room. In this way, the peaetration can be r.apidly isolated when a need for primary containment i s ol at i on i s i ndi cat e d . Due t o the s i ze of t he pr i ma r y containment purge line penetration and the fact that,those penetrations exhaus.t dire-ctly from the containme.nt atmosphere to the environment, the penetration flow path conta1.ning these valves is not allowed tu be operated ~nder administrative controls .
* PBAPS UN IT 2                          B 3.6-18                          Revision No. 145
 
PCIVs B 3.6.l.3
* BASES ACTIONS (continued)
A second Note has been added to provide clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, si'hce the Requtred .Actions for each Ct:mditi*on provide appropriate compensatory actions for each inoperable PCIV.
Complying, with the Required Actions may allow for continued operation., and subsequent inoperable PCIVs are governed by subsequent Condition entry and appli.cation of associated Required Actions.
* The ACTIONS are modified by Notes 3 and 4. Note 3 ensures that appropriate reaedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable PCIV (e.g., an Emergency Core Cooling Systems subsystem is inoperable due to a failed open test return valve.). Note 4 ensures appropriate remedial actions are taken when the primary containment leakage limits are exceeded. Pursuant to LCO 3.0.6, these actions would not be required even when the associated LCO is not met.
Therefore, Notes 3 and 4 are added to require the proper actions be taken .
* -- --- ---- -- - ~
A.I and*A.2
                    -----W-i-th-one--=-or--more--penetrat i;on *-flow---path*s-wi th~one-PC-r-v--- -
inoper:able except for HSIV leakage. not within limit, the affected penetration flow paths must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed ~nd de-activated automatic valve, a closed manual valve,. a blind flange, and a check valve with flow through the valve secllred. For a penetration. isolated in accordance with Required Action. A.1, the device used to isolate the penetration should be the closest available valve to the primary containment. The Required Action must be completed within the 4 hour Completion Time (8 hours for main steam lines}. The Completion Time of 4 hours is reasonable conside.ring the Ume required to isolate the penetration arid the relative importance of supporting primary containment OPERABILITY during MODES 1 1 2, an~ 3-.
For main steam lines, an 8 hour Completion Tim:e is allowed.
The Completion Time of 8 hours for the main steam lines
{continued)
* PBAPS UNIT 2                              B 3.6-19                              Revi s,i on No. O
 
PCIVs B 3.6.1.3
* BASES ACTION$      A.1 and A.2 (contfmued) allows a period of time to restore the MSIVs to OPERABLE status given the fact that MSIV closure will result in isolation of the main steam line(s) arid a pote,ntial for p1ant shutdown.
For affected pen et rations that ha.ve been i so 1ated in accordance with Required Action A.1, the affected
              .penetration flow path(s) must be verified to be isolated on a periodic basis. This is ne.cessary to ensure that primary containment penetrations 0equired to be isolated following an accident, and no l anger capab 1e of being automati ca,l ly isolated, will be in the isolation position should an event occur. This Required Action does not require any testing or device ma.nipulation. Rather, it involves verification that those devices outside containment and capable of potentially being mispositi,qned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside primary containment" is appropriate because the devices are operated under administrative controls and the probability of their misalignment is 1ow. For the devi ce.s
* inside primary containment, the time period specified "prior to entering MODE 2 or 3 from MODE 4, if primary containment was de-inerted while in MODE 4, if riot performed wHhin the ptevfous92 days" is 1:iaised on engineering J uagrnent ancl is --~~----
considered reasonable in view of the inaccessibility of the devices a.nd other administrptive controls ensuring that device misalignment is an unlikely possibility.
Condition A is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with two PCIVs. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions.
Required Action A.2 is modified by two Notes. Note 1 applies to isolation devices located in high radiation areas, and allows them to be verified by use of administrative means.
Allowing verification by administrative means is considered acceptable, since access to these. areas is typically restricted. Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and allaws these devices to be verified closed by use of administrative means. Allowing verification by administrative means is*
considered acceptable, since the f~nction of locking, sealing, or securing components is to ensure that these devices are not inadvertently repositioned. Therefore, the probability of misalignme,nt, once they have been verified to be in the proper position, is low .
(continued)
PBAPS UNIT 2                  B 3.6-20                        Revision No. 57
 
PCIVs B 3 .* 6.1.3
* BASES ACTIONS (continued)
Ll With one or more penetration flow paths with two PCIV~
inoperable except due to MS IV leakage not within l i.mi t, either the inoperable PCIVs must be restored to OPERABLE status or the affected penetration flow path must be isolated within 1 hour. The method of isolati'on must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure.
Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. The 1 hour Completion Time is consistent with the ACTIONS of LCO 3.6.1.1.
Condition Bis modified by a Not~ indicating this Condition is only applicable to penetration flow paths with two PCIVs.
For penetration flow paths with one PCrV, Condition C provides the appropriate Required Actions.
C.1 and C.2 With one or more penetration flow paths with one PCIV inoperable, the inoperable valve must be restored to OPERABLE status or the affected penetration flow path must be--i siJl-a*ted-;---The--metnod of-i so-lat ion-must *foc-l1..1de-the~e- ~ -~- --
* of at least one isolatfon barrier that cannot be adversely affected by a single active failure. lsolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve. and a blind flange.
A check valve may not be used to isolate the affected penetration. The Completion Time of 4 hours is reasonable considering the time required to isolate the penetration and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. The. Completion Time of 72 hours for penetrations with a closed system is _
reasonable considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3.
The clbsed system must also meet the requirements of Reference 6. The Completion Time of 72 hours is also reasonable considering the instrument and the small pipe diameter of penetration (hence, reliability) to act as a penetration i sol at ton boundary and the small pipe diameter of the affe~ted penetrations.
* for affected penetrations that have been isolotetl in accordance with Required Action C.1, the affected penetration fl ow* pa.th ( s) must be verified to be isolated on (continued)
PBAPS UNIT 2                            B 3.6-21                          Revision No. 57
 
PCIVs B 3.6.1.3
* BASES.
ACrION.S                C.1 and C.2 (continued) a perfodic bas*is. Thts is necessary to ensure that_primary containment penetr1ati ons required to be isolated following an accident, and no lbrtger ~apable of being automatically isolated, will b"e in the isolation position shou1d a.ri event occur. This Required Action doe$ not require any testing or valve manipulation. Rather, it involves verification, through a system walkdown, that those valves outside cont~i~ment and cap~ble of potentially being mispositioned are in the correct posftio.n. The Completion Time of "once per 31 days for isolation devices oijtside primary                              .
containment" is appropriate because the valves are operated t.:lnde.r administrative controls and the probability of their misalignment is low. For the valves ins*ide primary containment, the time period specified hprior to entering MODE 2 or 3 from MODE 4, if *pr*imary containmerrt was de-inerted while in MODE 4, if not performed within.the previous 92 days" is based on engi'neering ,ju.dgment a*nd is considered reasonable in view of the inaccessibility of the valves and other administrative controls ensuring that valve misalignment is an uniikely possibility.
Condition C is modified by a, Note indicating that this
~~-,~~~~'  ~~
Condition is only applicable to penetration flow paths *with only one PCIV. For penetration flow paths wHh two PCIVs, Conditions A and B provide the appropriate Required Actions.
                  -----~--,---..,.___,___            ~~-  --=---=-~---            , ~~ ...... - - - . - - - - - . - - ~ ~ ~ - ~ - -
Requireci Acti.on C.2 is modifie:d by two Notes. N,ote 1 applies to valves and b1ind flang,es located in high radiation areas and allows them to be verified by use of administrative means. Allowing verification by administrative means is considered acceptable, since acc-ess to the.se areas is typically restricted. Note 2 applies to isolation devices that are locked, sealed, or other~ise secured in position and allows these devices to be verified cl~sed by use of admi ni str1ati ve means. A11 owi n,g verification' by administrative means is considered acceptable, since the function of locking, Sealing, or securing components is to ensure that these devices are not inadvertent1y repositio~ed.
Thetefore, the prob~bility of misalignment of the~e valves, once. they have been verified to ba in the proper p"ositi on, is 1ow.
l1...l With any MSIV leakage rate not.within limit, the assumptions o.f the safety analysis are not met. Therefore, the leakage must be restored ta with1n limit within 8 hours.
Restoration can be accomplished by isolating the penetration that caused the limit to be exceeded by use of one closed and d~-activated automatic valve, closed man~al valve, nr blind flange. W,hen a penetration is isolated, the Te*akage
( co:nti n.ued)
PBAPS UN IT 2                                B 3.,6-22                      Reyision No. 57
 
PCIVs B 3.6.1.3 BASES ACT!ONS            Ll (continued}
rate for the isolated penetration is assumed to be the actual pathway 1eakage through the isolation device. If two isolation devices are used to isolate the penetration, the leakage rate is assumed to be the lesser actual pathway leakage of the twio devices. The 8 hour Completion Time is reasonable constdering the time required to restore the leakage by isolating the penetration, the fact that MSIV closure will result in isolation of the main steam line and a potential for plant shutdown, and the relative importance of MSIV leakage to the overall containment function~
E.l. E.2.1. and E.2.2 The accumulated time tha.t the large containment purge and/ar vent valves (6" and 18M vent valves) are open, when reactor pressure is greater than 100 psig and the reactor is in MODES 1 or 2. is limited to 90 hours per calendar year. This will 1imit the total time that a flo~ path exfsts through certain containment penetrations. The design analysis (Reference 7) assumes that the containment remains at atmospheric pressure
,.                            for the determination of ECCS NPSH' during a LO.CA.
Consequently, there exists minimal impact on plant risk rasulting from challenges to ECCS NPSH dur1ng a LOCA while
----- - -- ~ - --- ~---- -------p -ryi~Tn:e-4-=nom----coitfpl rn onTirne to-, soTate -fne -- -~--
penetration 1s considered a reasonable amount of time to ensure compli,ance with the design analysis. H the penetration ts not isolated within the specified 4-hour time
                                ~eriod, then the plant must be brought to at least MODE 3 within 12, hours and to MODE 4 within 36 hours. The a 11 owed 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 p1ant systems.
F.1 and P.2 If any Required Action and,associated Completion Time cannot be met in MODE 1, 2, or 3, the p1ant must be brought to a MODE i,n w:hi ch the LCO does not apply. TO achi eve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are r~asonable, based on operating experience,, to reach the required pl ant cond i ti on,s from full power conditions in an orderly mann_er and wHhout challenging pl ant systems.                  -
(continued)
* l?BAPS UNIT 2                          B 3.6-23                      Revision No. 144
 
PC IVs B 3.6.1.3
* BASES ACTIONS (continued)
Ll If any Required Action and associated Completion Time cannot be met for PCIV(s) require~ to be OPERABLE during MODE 4 or 5 ., t he unit mu*s t be pl a ced i n a con dtt i on 1n whi c h t he LC O does not apply. Action must be immediately initiated to restore the valve(s) to OPERABLE status. This allows RHR to remain in service while actions are being taken to restore the valve.                                          ,
(continued)
PBAPS UNIT 2                        B 3.6-23a                        Revision No. 145
 
PClVs B 3.6.1.3
* BASES 1
(conttnued)
SUR VEI LLANCE REQUIREMENTS SR  3.6.1.3.1 Verifying that the nitrogen inventory is equivalent to a level in the liquid nitrogen tank of~ 22 inches water column(~ 124,000 scf at 250 psig) will ensure at l~ast 7 days of post-LOCA SGIG System operation. This minimum volume of nitrogen allows. suffi.cient time after an accident to replenish the nitrogen supply in order to maintain the contai"nment isolation function. The inventory is verified to ensure that the system is capable of performing its intended isolation function when required. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR  3 , 6 , 1.3 . 2 This SR ensures that the pressure in the SGIG System header is~ 80 psig. This ensures that the post-LOCA nitrogen pressure provided to the valve operators and valve seals is adequate for the SGIG System to perform its design function.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR  3.6.1.3.3 This SR ensures that the primary containment purge and exhaust valves ~re closed as required or, if ~pen, open for an allowable reason. If a purge valve is open in violation of this SR, the valve is considered inoperable (Condition A appnes). The SR is modified by a Note stating that the SR is not required to be met when the purge and exhaust valves are open for the stated reasons. The Note states that these valves may be opened for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that req~ire the valves to be open.
Th e 6 i nch and 18 i nch pur g,e va1ve s and 18 i nc h ex ha ust PBAPS UN IT 2                            B 3.6-24                      'Revision No. 91
 
PCIVs 8"3.6.l..3
* BASES' SURVEILLANCE REQUIREMENTS SR    3,6,1.3,3        (continued) va*lves are capable of closing in the environment foll9wing a LOCA. Therefore, these valves are allowed to be open for limi~ed periods of t1me.
SR    3.6,1.3.4-Thi-S SR verif"ies that each primary containment fsolatton manual valve and _blind flange th,at ts located o.uts i de primary containment and is not locked} se:aled,, or otherwise secured and is required ta be closed during accident conditions is clos.ed. Ttre SR helps to ensure that post accident leakage of tadioactive f1uids or g~ses out~i~e the pr i ma r y con ta i nm en t bound a r y i s with i n des i gn l i rn its .
This S~ does not require any testing or valve manipulation.
Ratherj ~~ involves verification that tHose PCIVs outside primary containment, and capable of being mispositioned. are in t~e correct position. Since verification of val~e positi'oB for PCIVs outside primary containment js relatively
* eas,y, the Frequency was oh-0.sen to provide. added assurance that the PC IVs are. in the correct positions. lhi s SR does
  ~~~~~--------~not api:ily !_b__J_q_lves_J:_hat are. locked, seale9, or otherwise - ~ ~ =
secured in the closed position, since these valves were verified to be in tl:le correct position upon locking, sealing, or securing.
Three Notes have been added t0 this SR. The first Note*
allows valves and blind flangas located in high radiation areas to be verified by use of administrative controls.
Allowi.ng verification by _administr*ative contro.lS is corrsidered acceptable since the primary containment is in,erted an,d a.cces_s to the;;e areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment o.f these PCIVs, once they have be en ve r if i ed to be i n t he pr op-e r po s it i (;) n , i s Tow , A second Note has been inc::luded to clarify that PCIVs that are open under adm'inistrative controls: ar-e not required to meet the SR during the time that the PCIVs are open. A third Note states that performance of the SR is not required for test taps with \l dii:lmeter::;; 1 i'nc;.h. It is the intent that this SR must sti 11 be met, but actual performance , s n-ot required for test taps with a diameter::;; 1 inch. The Note 3 allowance is consistent with the original plact licensing basis .
* PBAPS UN IT 2                                                                Revision No. 86
 
PCI\Js B 3.6.1.3
* BASES SURVEILLANCE REQUIREMENTS (continued)
SR    3.6.1.3.5 This SR verifies that each primary containment manual isolation valve and blind flange that is located inside primary containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside the primary containment boundary is within design limits. For PCIVs inside primary containment, the Frequency defined as "prior to entering MODE 2 or 3 from MODE 4 1f primary containment was de~inerte;d while in MODE 4, if not performed within the previous 92 days'' is appropriate since these PCIVs are operated under administrative controls and the probability of their misalignment is low. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these valves were verified to be in the correct position upon locking, sealingj or securing.
Two N-otes have been ad.ded to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by us~ of administrative controls. Allowing verification by administrative controls is considered
* acceptable since the primary containment is inerted and access to_these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the
                - -prcilia5TTTty Qf mfsal i gnment of these PC I Vs, OflCe they have been verified to be in their proper position, is low. A second Note has been included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open.
SR    3.6.I.3.6 The trav,ers1ng incore prape (TIP) shear isolation valves are actuated ty explosive charges. Survei 11 ance of explVii ve charge continuity provides assurance that TIP valves will actua.te when requ1 red. Other admi ni strati ve c::ontrol s, such as those that limit the shelf life of the explosive ch-arges, must be followed. The Surveillance Frequency is controlled u.nder the Survei 11 ance Frequency Control Program. -
SR    3.6.1.3.7 Verifying the correct alignment for each manual valve in the SGIG System required flow paths provides assurance that the proper flow paths exist for system operation. This SR does not app1y to valves that are locked or otherwise secured in
* PBAPS UN IT 2                      B 3 *.6-26                      Revision No. 86
 
PCIVs B 3.6.1.3
* BASES SURVEILLANCE REQUIREMENTS SR  3.6.1.3.7        (continued) position, since these valves were verified to be in the correct position pn.or to locking or securing. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being nuspositioned are in the correct position. This SR does not apply to valves that cannot be inadves:-tently misaligned, such as check valves. The Surveillance Frequency is controlled under the Su~veillahce Frequency Control Program.
SR    3.6.1.3.8 Verifying the isolation time of each power operated automatic PCIV is within limits is required to demonstrate OPERABILITY. MSIVs may be excluded from chis SR since MSIV ful1 closure isolation time is d.eroonstr:ated PY SR 3. 6 .1. 3. 9.
The isolation time test ensures that tne valve will isolate in a time period less than or equal to that assumed in the s.afety analyses. The isol,ation time is in acco:?:dance with Reference. 2 or the requirements of the INSERVICE TESTING PROGRAM which ever is more conservative. The Frequency of this SR is in accordance with the requirements of the
        ~- -- -- -- --l-nseEv-i-ce-'Iest-ing- P-f0g-ram.-- - -- -- ----
SR    3
* 6
* 1. 3
* 9 Verifying that the .:solation time of each MSIV is within the specified limits is required to demonstr~te OPEAABILITY.
The isolation tine test ensures th{it the HSIV will isolate in a time period that does not exceed the times assumed in the DBA analyses, This ensures that the calculated radiological consequences of these events remain within 10 CFR 50.67 limits as modified in Regulatory Guide 1.183, Table 6. The Frequency of this SR is in accordance with the requireme~ts of the INSERVICE TESTING PR0GAA!1.
SR  3.6.1.3.10 Automatic PCIVs close on a primary oontainment isolatior.
signal to prevent leakage of radioactive material from primary containment following a DBA. This SR ensures that each automatic PCIV will actuate to its isolation position en a primary contai~ment isolat~on signal. The LOGIC SYSTEM continued PaAPS UNIT 2                                8 3.6-27                  Revision No. 140
 
f'.>CIVs B 3.6.1.3
* BASE,S SURVEILLANCE REQUIREMENTS SR 3.6.1.3.10              (continued)
FUNCTIONAL TEST in LC0 3.3.6.1 overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surve11Tance Frequency Control Program.
SR      3
* 6 . 1. 3 . 11 This SR re:quires a demonstration that a representative sample of reactor instrumentation line excess flow check valve (EFCVs) is OPERABLE by verifying that the valve actuates to the isolation position on a simulated instrument line break signal. The representative sample consists of an approximately equal number of EFCVs, such that each EFCV is tested at least once every 10 years (Nominal). In addition, the EFCVs in the sample are representative of the various plant configurations, models, sizes and op.erating environments. This ensures that any pote,ntially common problem with a specific type of application of EFCV is det~cted at the earliest possible time. This SR provide s 0
assurance that the instrumentation line EFCVs wil~ perform so that predicted radiDlogical consequences will not be
____ e.xc.e:e_cle.cL d_u rjJ1.g_a_ p_p_st_t:J..ltlecl j ns_tr_um_er]j:_ liD~ br~a l<,__~ven_t_. __ ___ _ ,_
The Surveillance Frequency is controlled under the                                                l Surveillance Frequency Control Program.                                                            I SR      3.6.1.3.12 The TIP she.ar iso1ation valves are actuated by e.xplosive charges. An in place functional test is not possible with this.design. The explosive squi~ is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same m~nufactured batch as the one fired or from another batch that has been certified by having one of the batch successfully fired. The Surv~illance Frequen~y 1s controlled under the Surveillance Frequency Control Program .
* PBAPS U~ IT 2                                  B 3.6-28                                  Revision No. 86
 
PClVs B 3.6.1.3 BASES S.URVEI LLANCE      SR 3.6.1.3.13 REQUIREMENTS (continued)      This SR ensures that in case the non-safety grade instrument air system is unavailable, the SGIG System will perform its design function to supply nitrogen gas at the required pressure for valve operators and valve seals supported by the SGIG System. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR  3,6.1.3,14 Total leakage through all four main steam ltnes must be~ 170_
scfh, ands 85 ~cfh for any one steam Tine, when tested at
                            ~ 25 psig. The analysis in Reference 1 is based on treatment of MSIV leakage as secondary containment bypass leakage, independent of the primary to secondary containment leakage analyzed at L6
* The Frequency is in accordance with the Primary Containment Leakage Rate Testing Program.
SR  3,6.1.3,15 Verifying the opening of each 6 inch and 18 incn primary
** _                        containment purge valve and each 18 inch primary containment
____ -~---- --~- _      _ __ exhaust valve 1s restricted-~ bl oc.kirr_g <levi ce_ to less than _________ _
or equal to the required maximum opening angle specified in the UFSAR (Ref. 4) is required to ensure that the valves can close under OBA conditions. Although the valves are designed to close under OBA conditions, evaluation of a LOCA concurr.ent with purging operations 1s no longer required to be evaluated with the implementation of Alternate Source Term. At other times pressurization concerns are not present. thus the purge and exhaust valves can be fully open.
The Surveillance Frequency is controlled under the Surveil1ance Frequency Control Program .
* PBAPS UN IT 2                        B 3.6-29                    Revision No. 144
 
P'CI Vs B 3.6.1.3
* BASES SURVEI LlANCE                  SR 3.6.1.3.16 REQUIREMENTS (continued)                The inflatable seal of each 6 inch and 18 inch primary containment purge valve. and each 18 inch P'rimary containment exhaust valve must be replaced periodically. This will allow the opportunity for replacement before gross leakage failure occurs.
REFERENCES                    1.      UFSAR, Chapter 14.
: 2.      UFSAR, Table 7.3 .. 1.
: 3.      10 CFR 50, Appendix J' Option B.
: 4.      UFSAR, Table 7. 3 .1, Note 17.
: 5.      UFSAR, Table 5.2.2.
: 6.      UFSAR, Table 7. 3 .1, Note 14.
: 7.      NrnC-33566P, '"Safety Analysis Report for Exelon Peach
                                    **  Bottom Atomic Power Sta ti on, Units 2 and 3, Constant Pressure. Power Uprate," Revision o.
  ;;:;..;.;;...;;;;;,;~;;;_~,;;;;;;;~=;;....;;~~~~~:;;;;;;;;;;;;;;;;;;;,;;;;*;;;;;;;:;;;*~-~*;;,;;.;-;;;;;;;;~~~~;:;;;.;_;;;.;.;;,:.;,.,;.,;;.,;,;;;:;;;;;;~. - - .-
PBAflS UNIT 2                                            B 3.6-30                                                Revision No. 114
 
Drywell Air Temperature B 3.6.1.4
* B. 3*.6  CONTAINMENT SYSTEMS B 3.6.l.4 Drywell Air Temperature BASES BACKGROUND              The drywell contains the reactor vessel and piping, which add heat to the airspace. 0rywell coolers remove heat and maintain a suitable environment. The average airspace temperature affects the calculated response to postulated Design Basis Accidents (DBAs). The limitatton en the drywell average ai.r temperature was <fevel oped as reasonable, based on ope.rating experience. ihe limitation on drywell air temperatu.re is used in the Reference 1 safety analyses.
APPLICABLE              Primary containment perfonnance is evaluated for a SAFETY ANALYSES          spectrum of break. sizes for postulated loss of coolant accidents {LOCAs) (Ref. 1). Among the inputs to the design basis analysis is the initial drywell average air temperature (Ref. 1). Analyses assume an initial average drywell air temperature of 145&deg;F. This limitatiQlil ensures that the safety analysts remains valid by maintaining the expected initial conditions and ensures that the peak LOCA drywell temperature does not exceed the maximum allowable*
--+- - ____,..____,.._ ----,.-------. - - - - ........ ~-
_J_runpJ~_r_aim:e_of-281 ~ L_(Ref--2)" .except- for-a ~brlef--per-i od---of- -- --
1ess than 20 seconds which was determined to be acceptable in References 1 and 3. Exceeding this design temperature may result in the degradation of the prima_ry containment structure under accident loads. Equipment inside primary containment required. to mitigate the effects of a DBA is designed to operate and be capab1e of operating under environmental conditions expected for the accident.
Drywell air temperature satisfies Criterion 2 of the NRC Policy Statement.
LCO                    In the event of a OBA, with an initial_ drywell average air temperature less than or equal to the !:.CO temperature limit, the resultant peak accident temperature is maintained within acceptable limits for the drywell. As a result, the ability of primary containment to perform its design function is -
ensured.
(continued)
PBAPS UNIT 2                                  8 3.6-31                          Revision No. 18
 
Drywell Air Temperature 83.6.1.4
* BASES (continued)
APPLICABILITY    In MODES l, _2, and 3, a DBA-""rc;uld cause a release of radi.oactive material to primary containment. In MODES 4 _
and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining dr,YWell average air temperature within the l1 mi t is not required in MODE 4 or 5.
ACTIONS          A.J.
With drywel l average air temperature not withi,n .the limit of the LCO, drywell average air temperature must be restored within 8 hours. The Required Action is necessary to return operation to within the bounds of the primary containment analysis. The 8 hour Completion Time is acceptable, considering the sensitivity of the analysis to variations in this parameter, and provides sufficient time to correct minor problems.
B.1 and B,2 If the drywell average ai.r temperature cannot be restored tQ within the limit within the required Completion lime, the
* plant must be brought to a MODE in which the LCO does not
----- --,..--~--~ -- ---apply-.-To--achieve-thts-status,--the7>iant711ust -be-brought'to:~ -
at least MODE 3 within 12 hours and to MODE 4 within 36 hours. lhe allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from ful1 power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE      SR 3 *6, I. 4. I REQUIREMENTS Verifying that the drywe]l average air temperature is within the LCO limit ensures that operation remains w.ith1n the li~its assumed for the primary contajnment analyses.
Drywell air temperature is monitored in various quadrants and at various elevations. Due to the shape of the drywell, a volumetric average is used to detenn1ne an accurate representation of the actual aver~ge temperature.
{continued}.
* PBAPS UNIT 2                        B 3.6-32                        Revision No. o
 
Drywell Air Temperature B 3.6.1.4
* BASES SURVEILLANCE  SR  3,6.1.4.1  (continued)
REQUIREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Contrdl Program.
REFERENCES    1. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0-.*
: 2. tJFSAR, Section 5.2.3.1.
: 3. De.l eted
* PBAPS UN IT 2                  B 3.6-33                  Revjsion No. 114
 
Reactor Building-to-Suppression Chambe.r Vacuum Breakers B 3.6.1.5
** B 3.6  CON~AINMENT SYSTEMS B 3. 6.1. 5 Reactor Building-to-Suppression Chamber Vacuum Breakers BASES BACKGROUND        The function of the reactor building-to-suppression chamber vacuum breakers is to relieve vacuum when primary containment depressuri zes below reactor bu 11 ding pressure.
If the drywe11 depressuri zes below reactor bu 11 d i,ng pressure, the negative differential pressure is mitigated by flow through the reactor buildilng-to-suppresston chamber vacuum breakers and through the suppression-chamber-to-drywell vacuum breakers. The design of the external (reactor building-to-suppression chamber): vacuum relief provisions consists of two vacuum breakers (a check valve and an air operated butterfly valve.), located in series in each of two lines from the reactor building to the suppression chamber airspace. The butterfly valve is actuated by a differential pressure .signal. The check valve is self actuating and can be manually operated for testing purposes. The two vacuum breakers in series must be closed to maintain a leak tight primary co.ntainment boundary *
* A  negative differential pressure across the drywe.11 wall is caused by rapid depressurization of the drywell. Events ttfat cause tnls rapid depressurization are cooling cycles, primary containment spray actuation, and steam condensation in the event of a primary system rupture. Reactor building-to-suppression chamber vacuum breakers prevent an excessive negative differentia1 pressure across the primary containment boundary. Cooling cycles result in minor pres*sure transients in the drywell, which occur slowly and are nonnally controlled by heating and ventilation equipment. Inadvertent spray actuation. results in: a significant negative pressure transient and is the design basis event postulated in sizing the external (reactor building-to-suppression chamber) vacuum breakers.
The external vacuum breakers are siz~d on the basis of the air flow from the secondary containment that is required to mitigate the depressurization transient and limit the maximum negative containment (suppression chamber) pressure to within des*ign 1imits. The maximum depressurization rate is a function of the primary containment spray flow rate and temperature and the assumed initial conditions of the (continued}
* PBAPS UNIT 2                          B 3.6-34                      Revision No. 0
 
Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5
* BASES BACKGROUND
( conti nu.ed) suppression chamber atmosphere. Low spray temperatures and atmospheric conditions that yield the minimum amount of contained noncondensible gases are assumed for conservatism.
The Safety Grade Instrument Gas (SGIG) System supplies pressurized nitrogen gas (from the Containment Atmospheric Dilution (CAD) System liquid nitrogen storage tank) as a safety grade pneumatfc source to the CAC System purge and exhaust isolation valve inflatab*le seals, the reactor building-to-suppression chamber vacuum breaker air operate~
isolation butterfly valves and inflatable seal, and the CAC and CAD Systems vent control air operated valves. The SGIG System thus p.erforms two distinct post-LOCA functions: Cl) supports containment isolation and (2) supports CAD System vent operation. SGIG System requirements are addressed for each of the supported system and components in LCO 3.6.1.3 "Primary Containment Isolation Valves (PCIVs)," LCO 3.6.1.5, and "Reactor Building-to-Suppression Chamber Vacuum Breakers." For the SG!G System, liquid nitrogen from the liquid nitrogen storage tank passes through the liquid nitrogen vaporizer where it is converted to a gas. The gas then flows into a Unit 2 header and a Unit 3 header separated by two manual globe valves. From each header, the
*    -                      gas then branches to each valve operator or valve seal
____________ -~- ___________ supplied by_the_ SG1G---3ystem~ _--lach_branch__J s--Sepa r:ated--from- ------
the header by a manual globe valve and a check valve.
To  support SGIG System functions, the nitrogen inventory is equivalent to a storage tank minimum required level of~ 22 inches water column, or a technically justified source of
                            *equivalent inventory ~ 124,000 scf at 250 psi g, and a minimum re,qui red SGIG System header pres.sure of 80 psi g.
APPLICABLE        Analytical methods and assumptions involving the reactor SAFETY ANALYSES    building-*tO.-su,ppression chamber vacuum breakers are used as part of the accident response of the containment systems.
Internal (suppression-chamber-to-drywell) and external
( reactor buil ding-to-suppression chamber) vacuum breakers
* PBAPS UN IT 2                        B 3.6-35                          Revision No. 91
 
Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6 .. l.5
* BASES APPLICABLE:
SAFETY ANALYSES (continued).
are provided as part of the prima.ry containment to li11it the negative differential pressure across the drywell and suppression chamber walls, which form part of the primar:y containment boundary.
The safety analyses asswae the external vacu1.111 breakers to be closed initially and to be fully open at 0.75 psid.
Additionally, of the four reactor building-to-suppression chamber vacuum breakers (two in each <>f the two lines from the reactor build'ing-to~suppression chamber airspace), one is assumed to fail in a closed position to satisfy the single active failure criterion. Design Basis Accident (OBA) analyses require the vacuum breakers to be closed initially and to remain closed and leak tight with positive primary containment pressure.
Three cases were considered in the safety analyses to determine the adequacy of the external vacuwu breakers:
: a. A  sma11 break loss of cool ant ace ident fo 11 owed by actuation of both drywell spray loops;
: b. Ina.dvertent actuation of one drywell spray loop during normal operation; and A* l>lfSt01.ateo1lBA assUl'Aing 1ow pres-sure coo 1ant            -- -- - --*
injection fl.ow out the Toss of cool ant accident break, which condenses the drywell ,steam.
The results of these three cases show that the external vacuum breakers, with an opening setpoint of 0.75 psid, are capable of 11ai.nta,ining the differential pressure within design limits.
The reactor building-to-suppression chamber vacuum breakers satisfy Criterion 3 of the NRC Policy Statement.
LCO            All reactor buildtng-to .. suppression chamber vatulllll breakers are requited to be OPERABLE to satisfy the assumptions used in the safety analyses. The requirement ensures that the two vacullll breakers (check valve and air operated butte.rfly valve) in each of the two lines from the reactor building to Ccontinyedl
* PBAPS UNil 2                          B 3.6-36                        Revision No., O
 
Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6. 1.5
* BASES LCO (continued).
the suppression chamber airspace are closed. Also, the requirement ensures both vacuum breakers in each line will open to relieve a negative. pressure in the_suppression chamber (except during testing. ot when performing tfleir intended funct ton)..
* In addition, for the reactor building-to-suppression chamber vacuut11 breakers to be considered OPERABLE and closed, the SGIG System supplying nitrogen gas to the air operated va1ves and i nfl atab1e sea1 of the v.acuum breakers must be OPERABLE.
APPLICABILITY      In HODES 1, 2, and 3, a. DBA cou1d result in excessive negative differential pressure act-oss the drywell wall caused by the rapid depressurization of the drywall. The event that-results in the limiting rapid depressurization of the drywell is the primary system rupture, whic:h purges the drywe 11 of air and f fl 1s the dr,YWe 11 free airspace wi ttl steam. Subsequent condensation of the steam would result in depressurizat1on of the drywell. The limiting pressure and temperature of the primary system prior to a DBA occur in MODES I, 2, and 3. Excessive negative pressure inside primary containment could also occur due to inadvertent
          - -~- -
initiation of the Drywell Spray System.
                  - - - - - - - - - - - . . . . .___ -~..,..______ --~-*:c--                  --
In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these HODES. Therefore, maintaining reactor btrilding-to-suppressiQn chambe.r vacull1fl breakers OPERABLE is, not required in MOOE 4 or 5.
ACTIONS            A Note has been added to provi_de clarification that, for the purpose of this LCO, separate Condition entry 1s a11 owed for each penetration flow path.
A:l With one or more lines with one vacuum breaker not closed, the leak tight primary containment boundary 111ay be threatened. Therefore, the inoperable. vacuUQl breakers must be restored to OPERABLE status or the open vacuum breaker closed within 72 hours. The 72 hour Completion Time is consistent with requirements for inoperable suppression chamber-to-drywell vacuum breakers iti .LCO 3 .. 6.1.6,
                                                                                  <continued)
PBAPS UNIT 2                                      B- 3.6-l7                .Revision No. O
 
Reactor Bui J di rig-to-Suppressi cm Chamber Vacuum Breakers B 3.6.1.5
* BASES ACTIONS            &J.    (continued)
                      "Suppress*ion Chamber-to-DrywelT Vacuum Breakers." The 72 hour Completion Time takes into account the redundant capability afforded by the remaining breakers, the fact that the OPERABLE brea~er in each of the ljnes is closed, and the low probability of an event occurring that would require the vacuum breakers to be OPERABLE during this period.
lL..l With one or more lines with two vacuum breakers not closed, primary containment i~tegrity is not maintained. Therefore, one open vacuum breaker must be closed within 1 hou~. This Compl e-ti on Time 1s consistent with the ACTI,ONS o.f LCO 3.6.1.1, "Primary Containment," which requires that primary containment be restore,d to OPERABLE status. within 1 hour.
Ll With onee lfoe w1th one or more vacuum breakers in0perable for opening. the leak tight prim.ary containment boundary is intact. The ability to mitigate an event that causes a containment depressurization is threatened if one or more
                - --v-acuum -b rea'k-e,r-s- i-n- *at 1-ea-s t- -o*n e --va01 um- bre-a ke--r- -pen et-r-a ti on ---- -----
are not OPERABLE. Therefore. the inoperable vacuum breaker must be restored to OPERABLE status within 72 hours. This is consistent With the Completion Time for Condition A and the fact that the leak tight primary containment boundary 'is being maintatned.
_D__._l If one line has one or more vacuum breakers inoperable for opening and they are not restored within the Completion lime in Condition C, the remaining vacuum breakers in the remaining line can provide the opening function. The plant must be brought to a condition it1 which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCD is acceptable because the plant risk in MODE 3 is similar to or
                    ~ ower than the risk in MODE 4 C Ref. 1) and because the time spent in MODE 3 to perfo("'llJ the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
The allowed Completion Time is reasonable, based on operating expertence, to reach the required plant conditions from full power conditions in an orderly manner an"d without challenging plant systems.
PBAPS UtfIT 2                              B 3.6-38                                    Revision No. 66
 
Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.5
* BASES ACTIONS (continued)
Ll With two lines with one or more vacuum breakers inoperable for opening, the primary containment boundary is intact.
However, in the event of a containment depressurization, the function of the vacuum breakers is lost. Therefore, all Vacuum breakers in one line must be restored to OPERABLE status within 1 hour. This Completion Time is consistent with the ACTION.S of LCO 3.6.1.1, which requires that primary containment be restored to OPERABLE status within 1 hour.
F.l and F.2 If any Required Action and ass0ciated Completion Time for Conditions A, B, or E cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, t~e plant must be brought to at least MODE 3 withl n 12 hours and to MODE 4 wit'h1 n 36 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.                            -
SURVEILLANCE  SR 3.6.1.5.1 REQUIREM_ENTS Verifying that th-e nitrogen inventory is equivalent to a level in the l tqui d nitrogen tank of ;::: 22 inches water
                --co-lumn* *(-~~1&#xa3;-4--;000 --s cf-at--25-0-p-s i*g )-wi*l *l- ens u,e-at" le ffst;-, ~
* days of post-LOCA SGIG System operation. This minimum voTume of nitrog,e.n allows sufficient time after an accident to replenish the nitrogen supply in order to maintain the desigh function of th~ reactor building-to-suppression vacuum breakers. The inventory is verified to ensure that the system is capable of performing its intended isolation function when required. The Surve.i l l ante Frequency is 1
controlled under the Survei 11 ance Frequency Control Prog*ram.
SR    3.6.1.5.2 This SR ensures that the pressure in the SGIG System header is~ 80 psig. This ensures that the post-LOCA nitrogen pressure provided to the valve operators and valve seals that is adequate for the SGIG to perform its design funtt1on. The Surveillance Frequency is c0ntrolled und~r the Surveillance Frequency Control Program.
PBAPS UN IT 2                            B 3.6-39                                  Revision No. 91
 
Reactor Building~to.suppression Chamber Vacuum Breakers B 3.6.1.5
* BASES SURVEILLANCE REQUIREMENTS (Continued)
SR    3.6.1.5.3 Each vacuum breaker is verified to be closed to ensure that a potential breach i~ the primary containment boundary is not present. This Surveillance is performed by observing local or control room indications of vacuum breaker position or by verifYing a differential pressure of 0.75 psid is maintained between the reactor building and suppression chamber. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
Two Notes are added to this SR. The first Note allows reactor building-to-suppressi0n chamber vacuum breakers opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of 0pening vacuum breakers are controlled by plant procedures and do not represent inoperable vacuum breakers. A second Note ts included to clarify that vacuum breakers open due to an actual differential pressure, are not considered as fa.i ling thi $ SR .
SR    3.6.1.5,4 Verifying the correct alignment for each manual valve in the SGIG Sy-stem required fl ow paths provides assurance that the~
proper fl ow paths exist for system op,erati on. This SR does not apply to valves that are locked or otherwfse secured in posit10n, since these valves were verified to be in the correct position prior to locking or securing. This SR. d:oes not require any testing or vahe manipulation;- r-ather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance fr~quency 1s controlled under the. *surveillance Frequency Control Program,
* PBAPS UNIT 2                      B 3.6-40                  Revision No. 86
 
Reactor Building-to-Suppression Chamber Vacuum Breakers 8 3.6.1.5
* 6ASES SUR VE IL LANCE REQUIREMENTS (continued)
SR 3,6,l,5,5 Each vacuum breaker must be cycled to e.nsure that i.t opens properly to perform its design function and'returns to its fully closed position. This ensures that the safety analysis assumptions are valid. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR  3 , 6, 1. 5 , 6 Demonstration of air operated vacuum breaker opening setpoint is necessary to ensure that the safety analysis assumption regarding vacuum breaker full o.pen differential pressure of~ 0.75 psid is valid. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR  3,6,1.5,7 This SR ensure.s that in case* the non~safety grade instrument air system is unavailable, the SGIG System will perform its
-~-----~-------        -~ jesign~nction to_SUifply nitrogen gas at the required ____ -------~
pressure for valve operators and valve seals supported by the SGIG System. The Surveillance Frequency is controlled under the Survei 11 ance Frequency Control Program.
REFERENCES          1.      NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Requjred End States for BWR Plants, December 2002 .
* PBAPS UN IT 2                          B 3.6-41                  Revision No. 86
 
Suppression Cham~r-to-Drywell Vacuum Breakers B 3.6.1.6 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.6 Suppression Chamber-to-Drywell Vacuum Breakers BASES BACKGROUND        The function of the suppression chamber-to-drywell vacuum breakers is to relieve vacuum in the drywall. There are 12 internal vacuwn breakers located on the vent header of the vent system between the drywe 11 and the suppression chamber, which allow air and steam flow from the supptession chamber to the drywell when the dr,YWell is at a negative pressure with respect to the suppression chamber.
Therefore, suppress'ion chamber-to-drywel l vac1,11111 breakers prevent an excessive .negative differential pressure across the wetwell drywell boundary. Each vacuum breaker h a self actuating valve, similar to a. check valve, which can be remotely operated for testing purposes.
A negative differential pressure across the drywell wall is caused by rapid depressurization of the dr~ll. Events that cause this rapid depressurization are cooling cycles, drywell spray actuation, and steam condensati.on from sprays or subcooled water reflood of a break in the event of a primary system rupture. Cooling cycles result i.n minor
*.                      pressure transients in the drywell that occur slowly_an~~are ___ . __
-~--- --- --------- *--nomcll:~01'ftrolled-byneat1ng ancrvenfilation equipment.
Spray actuati-on o.r spill of subcooled water out of a break results in 110re si,gnificant pressure transients and becomes important in sizing the internal vacuum breakers.
In the event of a primary system rupture, steam condensation within the drywe11 results in the most severe pressure.
transient. Following a primary system rupture, a.ir in the drywall is purged into the suppression chamber free airspace, leaving the drywell full of steam. Subsequent
                        - condensation of the steam can be caused in *two possible ways, namely, Emergency Core Cooling Systems flow from a recirculation line break, or dr_ywell spray actu~tion following a loss of coolant accident (lOCA). These two cases determine the maximum depressurization rate of the drywell.
In addition, the waterleg in the Mark I Vent System downcomer is controlled by the drywall-to-suppression chamber differential pressure. If the drywell pressur.e is less than the suppression chamber pressure, there.will be an increase in the vent waterleg. This will result in an *
(continued)
PBAPS UNIT 2                        B 3.6-42                        Revision No. O
 
Suppression Cnamber-to-Drywe]l Vacuum Breakers B 3.6.1.6 BASES BACKGROUND      increase in the water clearing inertia in the event of a (continued)  postulated LOCA, resulting in an increase in the peak drywell pressure. This in turn will result in an increase in the pool swell dynamic loads. The internal vacuum breakers limit the height of the waterleg in the vent system during normal operation.
APPLICABLE      Analytical methods and assumptions involving the SAFETY ANALYSE$  sup~ression chamber-to-dryweTl vacuum breakers are-used as part of the accident response of ~he primary containment systems. Internal (suppre-ssio.n chamber-:to-d.rywell) and external (reactor building- to-suppression chamber) vacuum breakers are provided as part of the primary containment to limit the negative differential pressure across tha drywell and suppression chamber walls that form part of the primary containment boundary.
The safety analyses assume that the internal vacuum breakers are closed initially and are fully open at a differential pressure of 0.5 ps1d. Additionally, 1 of the 9 internal vacuum breakers required to open is assumed to fail in a close.ct positi.on. The results of the analys.es show that the design pressure is not exceeded even under the worst case accident scena~i o. The vac.uutn. break_er opening differential pressure setpo1nt and the requirement that 9 of 12 vacuum
* _  _ _____ ----~-~--- breakers_!e GPERABL0re a re~_u~t of the_r.equirement 12laced ______ _
--------- -                on "tl1 vacuuinoreakers"---to 11m1 t Tne vent system wate-rl eg height. The total cross sectional area of the main vent system between the drywe1l and suppression chamber needed to fulfill this requirement has been established as a minimum of 51.5 times the total break area. In turn, the vacuum relief capacity between the drywell and suppression chamber should be 1/16 of the total main vent cross sectional area,
                          'with the valves set to operate at 0.5 psid differential pressure. This was the original design basis for Peach Bottom, which required 10 18" vacuum bre.akers to meet the 1/16 of the total main vent cross sectional area. However, the current d~sign basis requirement for 9 vacuum brea~ers required to be operable, one of which is assumed to fail to open (single active failure), is found in Reference 2.
Design Basis Accident (OBA) analyses require the vacuum breakers to be clo-sed initially and to remain closed and leak tight, until the suppression pool is at a positive pressure. relative to the drywel l. A11 suppression chamber-to-drywel 1 vacuum breakers are considered closed .if a leak test confirms that the bypass area b~tween the drywell and suppression chamber is less than or equivalent to a one-inch diameter hole (Ref. 1).
The suppression chamber-to-drywell vacuum breakers ~atisfy Criterion 3 of the NRC Policy Statement .
(continued)
PBAPS UN IT 2                        B 3.6-43                        Revision No. 44
 
                                      -suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6
* BASES LCO (continued)
                      .Only 9 of the 12 vacuum breakers must be OPERABLE for opening. All suppression chamber-to-drywell vacuum breakers are required to be closed (except when the vacuum breakers are perfonting their intended design function). All suppression _chamber-to-drywall vacuum breakers are considered closed, even if position indication shows that one or more vacuum breakers is not fu1 l y seated, if a leak test confirms that the bypass area between the drywell and suppress.ion chamber is less than or equivalent to a one-inch diameter hole. The vacuum breaker OPERABILITY requirement provides assurance that the drywell-to-suppression chamber negative differential pressure remains below the design value. The requirement that the vacuum breakers be closed ensures that there is no excessive bypass leakage should a LOCA occur.
APPLICABILITY        In MODES 1, 2, and 3, a OBA cou*l d result in excessive negative differential pressuf1! acr-oss the drywall wall, caused by the rapid depressurization of the d\"ywell. The event that results in the limiting rapid depressurization of the drywell is the primary system rupture that purges the drywell of air and fills the drywell free airspace with steam.. Subsequent condensation of the steara would result in depressu.ri zat ion of the drywe 11. The l i mi ting pressure and
        -~ -~ -- ~---temperature--of--the- pri11ary system-prtor---io-,;--DBA-o-ccurirr-- -- - - --
MODES 1, 2, and 3. Excessive negative pressure inside the drywell could also occur due to inadvertent actuation of the Drywell Spray System.
In MODES 4 and 5, the probability and consequences of these e;vents are reduc~d by the pressure and temperature limitations in these MODES; therefore, maintaining suppression chamber-to-drywall vacuum breakers OPERABLE 1-s not requtred in MODE 4 or 5.
ACTIONS            A.,l With ,one of the required vacuum breakers inoperable for opening (e.g., the vacuum breaker is not open and may be stuck closed or not within its opening setpoint limit, so that it would not function as designed during an event that depressurized the drywell), the remaining eight OPERABLE vacuum breakers are capable of providing the vacuum relief function.. However, overall .system reliability is reduced
{continued)
PBAPS UNIT 2                            B 3.6-44                        Revision No. 0
 
Suppression Chamber*to-Drywell Vacuum Breakers B 3.6,1.6
* BASES ACTIONS        A......l (continued) becaose a single failu*re in one of the remaining vacuum ,,k*'
breakers could result in an excessive s.uppres-sion chamber,"*
to-drywell differential pressure during a OBA, Therefore, with one of the nine required vacuum breakers inoperable, 72 hours is allowed to restore the inoperable vacuum breaker to OPERABLE status so that plant conditions are consistent with those assumed for the design basis analysis. The 72 hour Completion T1me is considered acceptable due to the low probability of an ev~nt in which the .remaining vacuum breaker capability would not be adequate.
If a required suppres~ion chamber-to-drywell vacuum breaker is inoperable for opening and i.s not restore{! to OPERABLE s.tatus within the required Completion Time, the plant must be brooght to a condition in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time
      ~~-----~s~_en1 ~iJJ..__MQD&#xa3;___J____to___.J1etlorJ1l_ +/-b._e___n.e__,;:e_s s_a t:.)LJ'.epa1-rsJo__tes1-.ore__+/-he ____ _
system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The* allowed Completion Time is reasonable, based on operating experience, to rea~h the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
Ll An open vacuum breaker gllows communication between the drywel1 and suppression chamber airspace, and, as a: result, there is the potential fo.r suppression chamber overpressurization due to this bypass leakage if a LOCA were to occur. Therefore, the open vacuum breaker must be closed. A short time is allowed to close the vacuum breaker due to the low probability of an event that would pressurize primary containment. If vacuum breaker position indication is not reliable, an alternate method of ~erify1ng that the vacuum breakers are closed must be performed within 10 hours. All suppression c.hamber-to-drywell vacuum br~akers are considered closed, even if the "not fully seated" indication is shown, 1f a leak test confirms that PBAPS UN IT 2                            B 3.fi-45                                            Revis1on No. 66
 
Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.6
* BASES ACTIONS            .L.l  ('cont inu,ed) the bypass area between the drywell and suppression chamber is less than or equivalent to a one-inch diameter hole (Ref. 1). The required 10 hour Completion Time is considered adequate to perform this test. If the leak test fails, not only must the Actions be taken (close the open vacuum breaker within 10 hours), but also the appropri~te Condition and Requi~ed kctfons of LCD 3.6.1,1, Primary Containment, must be entered.
D.l and D.2 If the open suppres~ion c~amber-to-drywell vacuum breaker cannot be closed 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 le~st MOOE 3 withln 12 hours and t0 MODE 4 within 36 hours. The allowed Completion Time~ are reasonable, based on operating experience, to reach the required p1ant conditions from full power conditions in an orderly manner
* REQUIREMENTS and without challenging plant systems.
----- ~-----suRV-ETtLANCE-- ---- SE 7~*6:::T.-6 , ---~----- - ~  --------- ----------~----- ---- ---
Each vacuum breaker is verified closed to ensure that this potential large bypass leakage path-is not present. This Survei Tl anc:e is performed by 0 bservi ng the vacuum breaker 1
position indicatio.n or by performing a leak test that confirms that the bypass area between the drywell and suppression chamber is less than or equivalent to a one-inch diameter hole. If the bypass test fails. not only must the vacuum bre.aker(s) be considered open and the appropriate Conditions and Required Actions of this LCO be entered, but also the appropriate. Condition and Required Action of LCO
: 3. 6 .1.1 must be. entered. The Survei 11 ance Frequency is controlled under the Survei 11 ance Frequency Control Program.
A Note is added to this SR which allows suppression chamber-to-drywell vacuum breakers opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of opening vacuum breakers are controlled by p~ant procedures and do not represent inoperable vacuum breakers .
* PBAPS UN IT 2                            B 3.6-46                    Revision No. 86
 
Suppression Cha,mber-to*Drywel l Vacuum Breakers B 3 . 6.1.6
* BASES SURVEILLANCE REQUIREMENTS (continued)
SR  3.6.1.6,2 Each required vacuum breaker must be cycled to ensure that it opens adequately to perform its design functio*l'l and ret~rns t0 the fully closed posftion. This ensures that the safety analysis assumptiorrs* are valid. The Surveillance Frequency is controlled under the Survei1lance Frequency Contro1 Program.
SR 3.6.1.6.3 Verification of the vacuum breaker setpoint for full opening is necessary to e~sure that the safety analysis assumption regarding vacuum breaker full open differential pressure of 0.5 psid is valid. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
REFERENCES            1. S~fety Evaluation by the Office of Nuclear Reactor Regulation Supporting Amendment Nos. 127 and, 130 to Facility Operating License Nos. DPR-44 and DPR-56, dated February 18, 1988.
____________ --~~- _M.l;,..::0J_6_l, _~D_et. _,ti.c_tu_aJ_ tt We_tw_e lJ__t_o__ llr.yw_e l T__\la c.uulfl__ __ -----.- _
Breakers Reqd."
: 3. NEDC-32~88-A,. Revision 2, Technical .Justificatio.n to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002 .
* PBAPS UN IT 2                                    B 3.6-47                                        Revision No. 86
 
Suppression Pool Average Temperature I
B 3.6.2ol B 3.6 CONTAINMENT SYSTEMS B 3.6.2~1 Suppression Pool Average Temperature BASES BACKGROUND      The suppression chamber is a toroidal shaped, steel pressure vessel containing a volume of water called the suppression pool. The suppression pool is designed to absorb the decay 1
heat and sensible energy released during a reactor blowdown from safety/relie'f valve discharges or from Design Basis .
Accidents (DBAs). The suppression pool must quench all the steam released through the downcomer lines during a loss of coolant accident (LOCA). This is the essential ntUigat1ve feature of a pressure suppression containment that ensures that the peak containment pressure is mainta.ined below the maximum allowable pressure for DBAs (56 psig). The suppression pool must also condense steam from steam exhaust lines 1n the turbine driven systems (i.e., the High Pressure Coolant lnjecti'on System and Reactor Core Isolation Cooling System). Suppression pool average temperature (along with LCO 3.6.2.2, *suppression Pool Water LeveP) is a key indication of the capacity of the suppressi,on pool to fulfill these requirements~
The technical concerns that lead to the developi:nent of suppression pool average temperature limits are as follows:
: a. Complete steam. condensation-the original l:imtt for the end .of a LOCA bl owdown was 110
* F, based on the Bodega Bay and Hwnboldt Bay Tests.;
: b. Primary containment peak pressure and temperature-design pressure is 56 psig and design temperature is 281 *f (Ref. 1);
: c. Condensation oscillation loads-maximum allowable initial temperature is 11o*F.
APPLICABLE        The postulated OBA against which the primary containment SAFETY ANALYSES  performance is evaluated is the entire spectrum of postulated pipe breaks within the primary containment.
Inputs to the safety analyses include initial suppression pool water volume and suppression pool temperature (Ref. 2) .*
An initial pool temperature of 95*f is assumed for the (continued)
PBAPS UNIT 2                        B 3.6-48                        Revision No. O
 
Suppression Pool Average Temperature B 3.6.2.1 I BASES APPLICABLE      Reference I and Reference 2 analyses. Reactor shutdown at a SAFETY ANALYSES pool temperature of 110&deg;F and vessel depressurization at a (continued)  pool temperature of 120&deg;F are a,ssumed fo.r the Reference 2 analyses. The limit of 105&deg;F, a.t which testing is tenninated, is not used in the safety analyses because DBAs are assumed to not initiate during unit testing.
Suppression pool average temperature satisfies Criteria 2 and 3 of the NRC Policy Statement.
LCO            A l imitation on the suppress ion pool average tempera tu.re is required to provide assurance that the containment conditions assumed for the safety analyses. are met. This l tmitation subsequently ensures that peak primary containment pressures and. temperatures do not exceed. maximum allowable values during a postulated DBA or any transient resulting in heatup of the suppression pool. The LCO requirements are~
: a. Average temperature :s: 95&deg;F when any OPERABLE wide range neutron monitor (WRNM) channel is at l.OOEO %
power or above and no testing that adds heat to the suppression pool is being performed. This requirement ensures that licensing bases initial conditions are
_ ___.,met _ __
: b. Average temperature :s: 105&deg;F when any OPERABLE WRNM' chann~l is at I.OOEO % power or above and testing that adds heat to the suppression pool is being perfonned.
This required value ensures that the unft has testing flexibility, and was selected to provide margin below the 110&deg;F 1imit at which reactor shutdown js required.
When testing ends, temperature must be restored to
:s: 95&deg;F within 24 hours according to Required Action A.2. Therefore, the time period that the temperature is> 95&deg;F is short enough not to cause a significant increase in unit risk.
: c. Average temperatures 110&deg;F when all OPERABLE WRNM channels are below 1.00EO % power. This requirement ensures that the unft will be shut down at > 110&deg; F.
The pool is des1gned to absorb decay heat and sensible heat but could be heated beyond design limits by the steam generated if the reactor is not shut down.
(continued}
PBAPS UNIT 2                        B 3.6-49                    Revision No. 24
 
Suppression Pool Average Temperature.
B 3.6.2.1 I          BASES LCO            Note that WRNM indication at 1.00EO % power is a (continued}  convenient measure of*when the reactor ts producing power essentially equivalent to 1% RJP. At this power level; heat input is approximately equal to nonnal system heat losses ..
APPLICABILITY    In MODES 1, 2, and 3~ a OBA could cause significant heatup of the suppression pool. In MODES 4 and 5, the probability and consequences Of these events are reduced due to the
* pressure and temperature limitations in these MODES.
Therefore, maintaining suppression pool average temperature within limits is not required in MODE '4 or 5.
ACTIONS        A.I  and  A.2 With the. suppression pool average tempe.rature above the specified limit when not perfonning testing that adds heat to the suppression pool and when above the specified power indication, the initial conditions exceed the condition,s assumed for the Reference I, 2, and 3 analy,ses. However, primary containment cooling capability still exists, a,:id the primary containment pressure suppresston function will occur at temperatures well above those assumed for safety analyses. Therefore, continaed operation i.s allowed for a
- - - - ~ - - - - ~ - - l - i mited-time...-lhe-2A-hour--Complet i.on_TJ meJs_adequate_t(l__ _ _
allow the suppre~ston pool average temperature to be restored below the limit. Additionally, when suppression pool temperature is> 95&deg;F, increased monitoring of the suppres.sion pool temperature is required to ensure that it remains~ 110&deg;F. The once per hour Completion Time is adequate based on past experience, which has shown that pool temperature increases relatively slowly except when testing that adds heat to the suppression pool is being performed.
Furthermore, the once per hour Completion Time is considered adequate in view of other indications in the control room,.
including alarms, to alert the operator to an abnormal suppression pool average temperature conditi-0n.
Ll If the suppression pool average temperature cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE 1n which the LCO does not apply . .To achieve this status, the power must be reduced to below l.OOEO % power for all OPERABLE WRNMs (continued}
PBAPS UNIT 2                        B 3.6-50                      Revision No. 24
 
Suppression Pool Average Temperature B 3.6.2.1 I BASES ACTIONS                  Ll      (continued) within 12 hours. The 12 hour Completion Time is reasonable, based on operating experience, to reduce power from full power conditions in an orderly manner and without challenging piant systems.
Ll Suppression pool avera~e temperature is allowed to be> 95&deg;F when any OPERABLE WRNM channel is at r.OOEO % power or above, and when testing that adds heat to the suppression p.oo 1 is being performed. However, if temperature is
                            > 105&deg;F, all testing must be invnediately suspended to preserve the heat absorption capability of the suppression pool. With the testing suspended, Condition A is entered and the Required Actions and associated Completton Times are applicable.
I                            D.l, D.2. and D.~
Suppression pool average temperature> 110&deg;F requires that the reactor be shut down il!lll1E!diat.ely *. This is accomplished
    --~----by-')>l-aci-ng-t-he-reaet--0r-mode-s-wi-teh--i-n-t-he- -s-hut-down-pos-4-t-i-on-. ---
Farther cooldown to MOOE 4 is required at nonnal cooldown rates (provided pool temperature remains s 120&deg;F).
Additionally, when suppression pool temperature is > 110&deg;F, increased monitoring of pool temperature is required to ensure that it remains s l20&deg;F. The once per 30 minute Completion Time. is adequate, based on ope.rating ex&#xb5;erience.
Given the high suppression pool average tempe.rature in this Condition, the monitoring Frequency is increased to twice that of Condition A. Fu.rthermore, the 30 minute Completion Time is considered adequate in view of other indications availab1e in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condi't i'on.
E.l and E.2 If suppression pool average temperature cannot be maintained at s 120&deg;F, the plant must be brought to a MODE in which the lCO does not apply. To achieve this status, the reactor
                            ,pressure must be reduced to < 200 psig within 12 hours, and
                , _ the pl ant must be brought to at 1east MODE 4 within
                - .- -~.,,,"'          -                -                    -    <continued}
PBAPS UNIT 2                                  B 3.6-51                        Revision No. 24
 
Suppression Pool Aver 9ge Temperature B 3.6.2 .. 1 I        BASES ACTIONS              E.1 and E.2 (continued) 36 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 ch~llenging plant systems.
Continued addition of heat to the suppression pool With suppression pool temperature > 120&deg; F could result in exceed1ng the design basis maximum allowable values for primary cohtainment temperature or pressure. Furthermore, if a blowdown were to occur when the temperature WijS
                              > 120&deg;F, the maximum allowable bulk and local temperatures could be exceeded very quickly.
SURVEILLANCE          SR    3,6.Z.1.1 REQUIREMENTS The suppression popl average temperature is regularly monitored to ensure that the required lim1ts are satisfied.
The average temperature is determined by taking an I                              arithmetic average of OPERABLE suppression pool water temperat1.1re channe.l s. The Survei 11 ance Frequency is controlled under the Survei_l1ance Frequency Control Program.
The 5 minute Frequency during testing is justified by the
  --- - - - - - - - - ---r-a-'l;es--a,t--wt9'i-eh--t-es-t--s--wH l~ea-t- up-t he-sup-press-i-on-pum-,-1:icrs been shown to be acceptable based on operating experience, and provides assurance that allow~ble pool temperatures are not exceeded. The Frequ*ency is further justified in view of other ind.1cations available in the control room, including alarms, to alert the operator to an abnorma1 suppression pool average temperature condition.
REFERENCES            1.      UfSAR, Section 5.2.
                              ~.      NEDC-33566P. ~safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pressure Power Uprate," Revision 0.
: 3.      NUREG-0783.
PBAPS UNIT 2                                  B, 3. 6-52.                      Revision No. 114
 
Suppression Pool Water Level B 3.6.2.2
'  B 3.6 CONTAINMENT SYSTEMS B 3.6.2.2 Suppression Pool Water Level BASES BACKGROUND      The suppression chamber is a toroidal shaped, stee1 pressure vessel containing a. volume of water called the suppression pool. The suppression pool is designed to absorb the energy associated with decay heat and sensible heat released duri.ng a reactor blowdown from safety/relief valve (S/RV) discharges or from a Design Basis Accident (OBA).. The suppression pool must quench a11 the steam released through the downcOll8r lines during a loss of cool ant accident      *
{LOCA). This is the essential mitigative feature 'of a.
pressure, suppression containment, which ensures that the peak containment pressure ts maintained below the 11aximU111 allowable pressure for DBAs (56 psig). The suppressjon pool must also condense steam from the steam exhaust lines in the turbine driven systems (i.e., High Pressure Coolant Injection {HPCI) System and Reactor Core Isolation Cao1ing (RCIC) System) and provides the main emergency water supply source for the reactor veisel. The .suppression pool volume ranges between 122,900 f} at the low water level limit of 14.5 feet and 127,300 ft at the high water level limit of 14.9 feet.
If the suppression pool water level' is too low, an insufficient amount of water would be available to adequately* condense the steam from the S/RV quenchers, main vents, or HPCI and RClC turbine exhaust lines. Low suppression pool water level could also result in an i.nadequate emergency makeup watar source to the Emergency Core Cooling System. The lower volume would also absorb less steam ehergy before heating up excessively. Therefore, a minimum suppression pool water level is specified.
If the suppression pool water level is too high, it could result in excessive clearing loads from S/RV discharges and excessive pool swell loads during a OBA LOCA. Therefol"e, a maximum pool water 1evel is specified. This LCO specifies an acceptable rahge t"o prevent the suppression pool water level from being e.ither too high or too low.
(continued}
PBAPS 1,JNIT 2                      B' 3 .6-53                    Revision No. O
 
Sup pres s i Q n Po o1 Wa te r Leve 1 B 3.6.2.2 I  BASES  (continued)
APPLICABLE          Initial suppression pool water level affects suppression SAFETY ANALYSES      pool temperature response calculations, calculated drywell pressure during vent clearing for a OBA, calculated pool swell loads for a DBA LOCA, and calculated 1oads due to S/RV discharges. Suppression pool water level must be maintained within the limits specified so'tnat the safety analysis of Reference 1 remains valid.
Suppression pool water level satisfies Criteria 2 and 3 Of the NRC PoJicy Statement.
LCO                  A    limit that suppression pool water level be~ 14,5 feet and
                        ~    14.9 feet is required to ensure that the primary containment conditions assumed for the safety analyses are met. Either the high or 1ow water l e.vel 1 i mits were used in the safety analyses, depending upon which is more conservative for a particular calculation.
APPUCAB-r LITY        In MODES 1, 2, and 3, a OBA would cause significant loads on I                      the prtmary containment. In MODES 4 and 5, the probabi11ty and. consequences of these events are reduced due to the pressure and temperature limitations in these MODES. The requirement for- maintaining suppression pool water level
                  ~-.,.Y-i,; t-A-~ +m4--t-s---+n-M0 f)f---4-or-~s--a-ctdr--ess-ea 1 nl:CUJ~5~.~4-,-,~iRc---=P'""'"'v,----7--
Wa t er Iriventory Control".
ACTIONS              Ll With suppression pool water level outside the 1 imits, the conditions assumed for the safety analyses are not met. If water level is below the mini.mum 1evel, the pressure suppression function still exists as long as main vents are covered, HPCI and RCIC turbine exhausts are covered, and S/RV quenchers are covered. If suppressiorl' pool water level is above the maximum level, protect1on against overpressurization still exists due to.the margin in the peak containment pressure analysis and. the e:apabi1ity of the Drywell Spray System. Therefore, continued operation for a limited time is allowed. Tbe 2 hour Completion Time is sufficient to restore suppression pool water level to within limits. Also, it takes into account the low probability of ao event i1T1pacting the suppression pool water level occurring during this interval.
I PBAPS UNIT 2                                  B 3.6-54                            Revisfon No. 145
 
Su~pression Pool Water Level B 3 . 6.2.2 I  BASES ACTIONS        B.l and B.2 (continued)
If suppression pool water level cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this stat~s. the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions ftom full power conditions in an orderly manner and without challenging plant systems.
SURVE.I LLANCE SR  3.6.2.2,1 REQUIREMENTS Verification of the suppr~ssion pool water level is to ensure that the required limits are satisfied. The Survei 11 ance Frequency is contro*l 7ed und,er the Su.rvei 11 ance Frequency Control Program.
I REFERENCES    1. UFSAR, Sections 5.2 and 14.6.3.
I
  ?BAPS UNIT 2                      B 3.6-56                      Revision No. 86
 
&S&f-lWWWW RHR Suppression P'ool Cooling B 3.6.2.3 I        B 3.6 B 3.6.2.3 CONTAINMENT SYS1EMS Residual Heat Removal (RHR) Suppression Pool Cooling BASES BACKGROUND            Following a Design Basis Accident (DBA), the RHR Suppression Pool Cooling System removes heat from the suppre.ssi on p.ool ..
The suppression poo1 is designed to absorb the sudden input of heat from the primary system. In the long term, the pool continues to absorb restctual heat generated by fuel in the reactor core. Some means must be provided to remove heat from the suppression pool so that the temperature insi~e: the primary containment remains within design limits. This functi ,irn i's prov, ded by two redundant RHR suppres_si on pool cooling subsystems. The purpose of this LC0 is to ensure that both subsystems are OPERABLE in applicable MODES.
Each RHR suppression pool cooling subsystem contains two motor driven pumps, two heat exchangers and a heat exchanger cross tie line, and is manually initiated and independently contro*11 ed. The two subsystems perform the suppression pool cooling function by circulqt'ing water fram the suppression I                              pool through the RHR heat exchangers and returning it to the suppression pool Via the full flow test lines. The High Pressure Service Water CHPSW) System circulating through the tube side of the heat exchangers, exchanges heat with the
          ----- - - --- -~~---supp r--as.s-i on-pGG~--wa-t---e r-a A d--e i-s-eh-a ~es-Hl+-s -he,a t---4:-o-t he -- - -
external heat sink.
The heat removal capability of one RHR pump and tvto heat exchangers in one subsystem are sufficient to meet the overall OBA pool cooling requirement for loss of coolant accidents (-LOCAs) and transient events such as a turbine trip or stuck open safety/relief valve CS/RV). S/RV leakage and High Pressure Coolant Injection System and Reactor Core Isolation Cooling System testing increase suppression pool temperature more slow1y. The RHR Suppression Pool Cooling System is also used to lower the suppression pool water bulk temperature following such events. -
Each subsystem is equ1pped with an RHR heat exchanger cross tie 1 i ne, l oca.ted downstream of each RHR pump discharge and upstream of each heat exchahger inlet, which allows one RHR pump to be aligned to supply bath RHR heat excha.ngers i.n the same subsystem for suppressio~ pool cooling when only one RHR pump is available. The RHR heat exchanger cross tie valve is normally 1/2losed, and is assumed by design.ed basis analyses to be plated in service one hour following a design basis accident or transient when insufficient electric power is available (e.g., single EOG failure) to operate two RHR pumps in a subsystem.
(continued)
PBAPS UNIT 2                                B 3.6-56                                Revision No. 114
 
S04544 RHR Suppression Pool Cooling B 3.6.2.3 BASES    (continued)
APPLICABLE          Reference 1 contains the results of analyses used to predict SAFETY ANALYSES      primary containment pressure and temperature following large and small break LOCAs. The intent of the analyses is to demonstrate that the heat removal capacity of the RHR
* Suppression Pool Cooling System is adequate to maintain the primary containment conditions within design limits. The suppression pool temperature is calculated to remain below the design limit.
The RHR Suppression Pool Cooling System satisfies Criterion 3 of the NRC Policy Statement.
LCO                  During a OBA, a minimum of one RHR suppression pool coo1ing subsystem is required to maintain the primary containment peak pressur.e and temperature below design l.imits (Ref. IL To ensure that these requirements are met, two RHR suppression pool cooling subsystems must be OPERABLE with power from two safety reloted independent power supplies.
Therefore, in the event of an accident, at least one subsystem is OPERABLE assuming the worst case sfngle active failure. An RHR suppression pool cooling subsystem is I                      OPERABLE when one of the pumps, two heat exchangers in the same RHR subsystem, the associated RHR heat exchanger cross tie line, two HPSW System pumps capable of providing cooling to the two heat exchangers al:ld associ ateri_pipin.g_,J-al 1/@s.,-----~
          ----------lrrstrmrrem~a*t7~anclcontrol s are OPERABLE.
Management of gas voids is important to RHR Suppression Pool Cooling System OPERABILITY.
APPLICABILITY        I~ MODES 1 1 2, and 3, a OBA could cause a release of radioactive material to primary containment and cause a heatup and pressurization of primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, the RHR Suppression Pool Cooling System is not required to be OPERABLE in MODE 4 or 5.
ACTIONS              Ll With one RHR suppression pool cooling subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition, the remaining RHR suppression pool cooling subsystem is adequa~e to perform the primary containment cooling function. However, the PBAPS UNIT 2                          B 3.6-57                      Revision No. 126
 
i:* ,.*y,-. ,****=-.- -~--~.::~~:*.:~i    BWMR!iiMitiid#@~~~~;~fflfflm?];
RHR Suppression Pool Cooling 8 3.6.2.3
'                                    BASES ACTIONS      U      (continued) overall re1iab111ty is reduced because a s1ngle failure 1n the OPERABLE subsyst.ern could result in reduced pl'imary containment cooling capability. The 7 day Comp1etion Time is acce*ptabl e i rr 1i ght of the ,redundant RHR suppression pool cooling capabilities afforded by the OPERABLE subsystem and the low prdbability of a DBA occurring during this period.
The Completion Time is modified by a note (s) for a one-time change that extends the 7-day Complet~on Time to 10 days four (4) times until December 31, 2021 to allow fo~ modifications to the. HPSW Syster.i. The compensatory measures i dent1fi ed in EGC License Amendment Request {{letter dated|date=September 28, 2018|text=letter dated September 28, 2018}} must be establishea and in effect. This change also affetts TS 3.6.2.4, 3.6.2.5, ana 3.7.1.
LI If one RHfi suppression pool cooling subsystem is inoperable and is not restored to OPERABLE status within the required Completion Thie, the pi ant rr.ust be brought to a c0ndi t1 on in .which We overall plant rfsk ls minimized. To achieve this status, the I
plant ~ust be brought t~ at least MODE 3 wft~in 12 hours.
Re11aining fn the Applicability of the LCO is acceptab1e because tile. plqnt risk in MODE 3 is s1:n1lar to or lcwer than the risk in MODE 4 (Ref. 2) and oecause the time s~e~t 1n MODE 3 to perform the neGessary repairs to restore the system to OPERABLE status _
          - ~ - __ ~-- __~~-~~~-~~icl--1--be-s-l:'l-O r-t-;------l-!oweve-r-;-vo-l1..1 '1t aT y-entyy-'fr.toMOOE 4 may be rrta de as it is also an accept3b~e low-risk state. The allowed Co:npletion 7fme 1s reasonable, based on operating exp2rience, to reach the required plant conditions from full power conditior.s ~n an orderly m:nner ara without cball eng1n&#xa3; pl ant systems.
Ll.
Witri  _two RHR si_;ppress101 pool cooling subsystems fno~erable, one subsystem wust be restored to OPERABLE status withi~ 8 hears. In this condition, there is a sJbstar.tial loss of the prfmary contain~ent pressure and temperat~re mitigation funct1on. The 8 ho~r Completion 7ime is based o~ this loss of function and is considered acceotable due to tne low proJcbil ity :if 3 DM ar.d betau~e al'ternat1 ve met-hoc!s to remove heat from primary containment are avai-:able.
0,1 and P, 2 If the Required Acti~n ana associeted Complet'or. Time of Condition C cannot be ~et, t~e plant ~ust be broug~t to a MODE in which the LCO ~ces not ~pply. To achieve this status, the plant ~ust be brought to at least MODE 3 within 12 hcJrs ar.d to MODE 4 within 36 hou~s. The allowec Completicn Times are reasonable, based en operating exper,ience, to reach tfie required plant conditions from full power conditions in a~
order1y manner and w~thout challeAging p1an~ systems.
I                              PBAPS UNIT 2                      B 3.6-58
{continued)
Revision No. 151
 
It    MAU f !&iW&it:ncr!".4)..M y;;&sect;fj&JUti&MJGWJ&j ifb1M-i!Gii RHR Suppression Pool Cooling I BASES  (continued)
B 3.6.2.3 SURVEILLANCE        SR    3.6.2.3.1 REQUIREMENTS Verifying the co.t:rect alignment for manual, power operated, and automatic \la,lves in the RHR suppression pool cooling mode. flow path provides assurance that th_e proper flow path exists for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since the$e valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is al~o allowed to be in the nonaccident position prov1.ded it can be aligned to the accident position within the time assumed in the accident analysi.s. This is acceptable since the RHR suppression pool cooling mode is manually initiated. This SR does not i:-equire any testing or valve manipulation; rather, it involves verification that those valves ca!=)able of being mispositioned are .:.n the correct position. ~his SR does not apply to valves that cannot be inadvertently m1s*aligned, such as check valves.
The Surveilla,nce Frequency is controlled under the surveillance Frequency Control Program.
I                      SR  3.6.2.3.2
  - - - - --------Ve-r1.fy+/-ng-th-at-each-re-quneu-FJ!R-pU!np-cfeveJ..6ps a flow rate
                      ~ 8,600 gpm while operating in the suppression pool cooling mode with flow through the associated heat exchanger ensures that plliilp performance has not degraded during the cycle.
Flow is a normal tesc of cent::-ifugal pu.-np performance.
required by A$ME Code (Ref. 3). This test confirms one point on the pump design curve, and the results are indicative of overall performance. Such inse.t:vice inspect.:.ons car.firm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal perforrna~ce. The Frequency of this SR is in accordance with the INSERVICE TESTING PROGRAM.
SR  3.6.2.3.3 Verification of manual transfer between the normal and alternate power source (4kV emergency bus) for each RHR motor-operated flow contro,l valve and each RHR cross-tie motor-operated valve demonstrates that AC power will be av~ilable to operate tne requ~red valves following loss of power to any single 4kV emergency bus. The ability to I  PBAPS UNIT 2                              B 3.6-59 (continued)
Revision No. 14 0
 
RHR Suppression Pool Cooling B 3.6.2.3 I BASES SURVEILLANCE  SR 3,6,2,3.3    (continued)
REQUIRliMENTS provide power to each RHR motor-operated flow control valve and eijch RHR ~ross-tie motor-operated valve from either of two independent 4kV emergency buses ensures that a s.illgle failure of a DG will not result in failure of the RHR motor-operated flow control valve and the RHR cross-tie motor-operated valve; therefore, failure of the manual transfer capability will. result in inoperability of the associated RHR Suppress-ron Pool Cool j ng subsystem. The Survei 11 ance Frequen~y is controlled under the Surveillance Frequency Control Program.
SR 3.6.2.3.4 RHR Suppression Pool Cooling System p1p1ng and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR
                .Suppression Pool Cooling Subsystems and may also prevent I
wat~r hammer and pump c~vitation.
Selection of RHR Suppression Pool Cooling System locations susceptible to gas accumulation is based on a review of system design information, i.ncTuding pj_QihQ and instrumentation rjraw1ngs. isometric drawings, plan and elevation drawings, and calculqtions. The design review is supplemented by system walk downs to valtdate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be tr~pped or difficult to remove during system maintenance or restoration. Susceptible
* locations depend o~ plant and system configuration, such as stand-by versus operating conditions.
The RHR Suppression Pool Cooling System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptHJl e locations. If accumulated gas is discovered that exceeds the acceptance criteria for the sus.cepti bl e location ( or the volum~ of accumulated gas at one or more susceptible locatiohs exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas ii eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the SR is met ind past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Suppression Pool Cooling System is not rendered inoperab1e by the accumurated gas (i.e., the system is (continued)
PBAPS UN IT 2                B 3 .. 6-59a                    Revision No. 127
 
RHR Suppression Pool Cooling B 3.6.2.3 I BASES SURVf I LLANCE SR 3.6.2.3.4    (continued)
REQUIREMENTS sufficfently filled w4th water), the Sur,eillance may be declared met. Accumulate0 gas should be eliminated or b~ought within the acceptance criteria limits.
RHR Suppression Pool Cooling System locations .susceptible to gas .accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the l oc.at_i on. Susceptible locations in the same system fl ow p.ath which are subject to the same gas ihtrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plaht configuration, or personnel safety.
For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. M~nitoring is not required for susceptible locatjons where the maximum potential accumulated gas void volume has been evaluated and determined to not cha 11 enge system OPERABILITY. The accuracy of the method I                used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.
The SR is modified by a Note. The Note recognizes that the scope of the surveillance is limited to the RHR system c.omponents. The HPSW system components have been determined to not be required to be in the scope of this surveillance due to operating experience and th*e design of the system.
The Surveillant~ Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulati0n.
REFE.RENCES    l.      UFSAR, Section 14.6.3.
: 2.      NEDC*32988-A, Revision 2, Technical Justification to Support Risk-Informe_d Modification to Selected Required End States for BWR Plants, December 2002.
: 3.      ASME Code for Operation and Maintenance of N*uclear Power Plants.
PBAPS UNIT 2.                      B 3.6-59b                  Revision No. 126  I -
 
W i'A RHR Suppression Pool Spray B 3.6.2.4 I    B 3.6  CONTAINMENT SYSTEMS B 3.6.2.4  Residual Heat Removal (RHR) Suppression Pool Spray BASES BACKGROUND          Following a Design Basis Accident (DBA), the RHR Suppression Pool $pray System removes heat frorn the suppression chamber a1rspace. The suppression pa,Ol is designed to absorb the 5Udden input of heat from the primary system from a DBA or a rapid depressuMzat1on of the reactor pressure vessel (RPV) th-r.ough safety/relief valves. The heat addition to the suppres.s.i on pool results in increased steam in the suppression chamber, which increases pr1mary containment pressure. Steam blowdown from a DBA can also bypass the suppression pool and end up in the suppTession chamber airspace. Some meahs must be provided to remove heat from the suppression chamber so that tbe pressure and temperature inside primary containment remain wi'thin analyzed design limits. This function is provided by two redundant RHR suppressio~ pool spray subsystems. The purpose of this LCO is to ensure that both subsystems are OPERABLE in applicab1e I                        .MODES.
Each of the RHR suppre~sion pool spray subsystems contains two motor driven pumps, two heat ex.cha ng~a_lJ1l___a_b_ea_L_ -~~
              --- -- ---exchanger crosstTeTTne,--whi ch a re manua 11 y initiated and independently controlled. The two RHR suppression pool spray subsystems perform the suppression pool spray function by circulating water from the suppression pool through the RHR hea.t exchangers and Ntur.ni ng it to the suppression pool spray spargers. The spargers only accommodate a sma11 portion of the total RHR p.ump -flow; the remainder of the flow returns to the suppression pool through the suppression pool cooling return line. T-hus, both suppression pool cooling and suppression pool spray functions a.re performed whep the .
Suppre*ssion Pool Spray System is initiated, High Pressure Service Water, circulating through the-tube side of the heat exchangers, exchanges heat with the suppression pool water and discharges this heat to the external heat sink. Either RHR suppression pool spray subsystem is sufficient to condense the steam from smal1 bypass leaks from the drywell to the suppression chamber airsp,ace during the postulated DBA.
Each suppression pool spray subsystem is equipped with a cross tie line, located downstream of each RHR pump discharge and upstream of each heat exchanger inlet, which allows one RHR pump to be aligned to supply both RHR heat exchangers in PBAPS UNIT 2                            B 3.6-60                    Revision No. 114
 
RHR Suppression Pool Spray B 3.6.2.4 BASES BACKGROUND          the same subsystem to remove additional heat from the (continued)      suppression pool when only one RHR pump is available. The cross tie is normally c1osed, and is assumed by design basis analyses to be placed in service one hour following a design basis accident or transient when insufficient electric power is available to operate two RHR pumps in a subsystem.
APPLICABLE          Reference 1 contains the results of ani;!lyses used to predict SAFETY ANALYSES    primary containment pressure and temperature following large and small break loss of coolant accidents. The intent of the ana1yses is to demonstrate that the pre.ssure reduction
                    . capacity of the RHR Suppression Pool Spray System is adequate to maintain the primary containment conditions with i n des i gn 1 i m1t s . The t i me hi s to r y f or pr i ma r y .
containment pressure is calculated to demonstrate that the maximum pressure remain~ below the design limit.
The RHR Suppression Pool Spray System satisfies Criterion 3 of th:e NRC Policy Statement.
LCD                In the event of a ffBA, a m1n1mum of one RHR suppression pool spray subsystem is required to mHigate potentia1 bypass
_________J_em.g:e_p..a:.:t.hs _a oiLJn aj n t.a.in_:t.b.a.. p.rJm a r&#xa5;--C--Q nta i nm ent. -P-W k pressure below the design iimits (Ref. 1). To ensure that these requirements are met, two RHR suppre,sston pool spray subsystems must be OPERABLE with power from two .safety related .independent power supplies. Therefore, in the event of an accident; at least one subsystem is OPERABLE assuming the worst case single active failure. An RHR .suppression pool spray subsystem is OPERABLE when one of the pumps, two he 9t exchangers in the same subsystem, the associated heat exchanger cross tie line,. two HPSW System pumps capable of providing cooling to the two heat exchangers and associated pipihg, valves, instrumentation, and controls are OPERABLL Management of gas voids is important to RHR Suppression Pool Sp.ray System OPERABILITY APPLICABILITY      In MODES 1, 2, and 3, a OBA could cause pressurization of primary containment. In MODES 4 and 5, the probability and consequences of the~e events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintain1ng RHR supp1ression pool spray subsystems OPERABLE I                    is not required i:n MODE 4 or 5.
(continued)
PBAPS UNIT 2                                      B 3.6-61                                    Revision No. 126
 
444i&#xa5;Ufk8#MH8&iafiit1!ZM\fkiMWffi1N.!tiZNlli""'itN\tt/&#xa5;W'.f1&#xa5;Kf&sect;Aj@ffis+iiMi RHR Suppression ~oor Spray B 3.6.2.4
'  BASES A'CTIONS (cont1nued)
A.J.
With one RHR suppression pool spray subsystem inoperab1e, the inoperable subsystem must be restored to OPERABLE status within 7 days. in th1s Condition, the remaining OPERABLE RHR suppre-ssi 011 pool spray subsystem is adequate to perform the primary co~ta1nment 6ypass leakage mitigation funct1on.
Howe~er, the overall reliability 1s reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment bypass mitigation capability. The 7 day Completion Time was chDsen in light of the redundant RHR suppression pool spray capabilitie'S afforded by the OPERABLE subsystem and the low probab1lity of a DBA occurring during this period.
The Completion Time is modified by a note (*) -For a one-time change that extends the 7-day Compl e:1 oh THne to 10 days four (4} times until December 31, 2021 to allow for modifjcations to the HPSW System. 1he compensatory meas~res identified in EGC License Amendment Request letter dated September 28. 2018 must be esta,bl i stied and in effect. This change al so a-ffects TS 3.6.2.3, 3.6.2',5, and 3.7.1.
I                        LI With both RHR suppression pool spray subsystems 1noperab~e.
at least one s~bsystem must be restorec to OPERABLE statLs
  ---------~wtttrtn-S-hot:rs. In this CondT"t1on, tnere is a SJ,bstantial loss of the primary containment bypass leakage m1t1gat1on functior.. The 8 hour Cowp~etion Time is basea on this loss of fuo:icti on a1c is consi aerea acceptable due :o tr.e low probability of a DBA and because altern2tive methods to re'llove heat from primary containment are a\laila,ble.
Ll If the i~operable R~R suppression pool spray subsystem(s) cannot be restored to OPERASLE status within the assotiated Co~pletion Ti~e, the plant must be b~ought to a MODE in wlricti the overall plal'l't risk is minimized. To achieve this status, the plaot must be brough~ to at least MOGE 3 within 12 hours. Re~eining in the Applicab411ty of the LCO is acceptable tec~use the ?lant risk 1n MODE 3 rs similar to or 1ow~r than the risk i.n MOiJ~ 4 (Ref. 2) and iJeca:use the tiJfle spetit in MODE 3 LO perforn the necessary repairs to restore the system to OPERABLE status wi 11 be short. However, vobntary entry into M::JDE 4 may be made as i: is also an acceptable low-risk state. The allowed Completion Time 1s reas.onabl e, based on op~rati ng exper1 ence, to reach the requ1 rec pl.art conditi ans from full power condit i ans i r. ari orderly manner and without challenging plant systems.
(continued)
PBAPS U~IT 2                              B 3.6-62                  Revision No. 151
 
RH R Suppression Pon l Spray I BASES    (continued)
B 3.6.2.4 SURVEILLANCE          SR 3.6.2.4.1 REQUIREMENTS Ver1fy1ng the correct alignment for manual, power operated, and automatic valves in th.e RHR suppression pool s,pray mode flow path provides assurance that the proper flow paths will exist for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also -01lowed to be in the nonaccident position provided it can be aligFled to the accident position within the time assumed in the accide~t analysis. This is acceptable since the RHR suppression pool tooling mode is manually initiated. This SR does not require any testing or va l ve- ma ni p ul a.t 1o n ; rather , it i nvol ves 1J e r if i cat i on t ha t those valves capable df being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.
The Surveillance Frequency is controlled under the Surveillance Frequency .Control Program.
I                      SR 3.6.2.4.2
    - - - - - - - -~-fl+-s---S I.H'-v--e--i..:J-1-a:n G e ~ e--P-f.G-P-m etl~--V--t-:i-f--.y-t-h a-t--th e.- -S-p ~a .1/- - - - - ...
nozzles a re not obstructed ancl that fl ow wi 11 be provided when requfred. The Survei 11 ance Frequency is controlled under the SarveilJance Frequency Control Program.
SR 3.6,2.4,3 Deleted (continued)
I PBAPS UN IT 2                                        B 3.6,-63                                      Revision No. 130
 
UPC ?#&#xa5;41MWHE RHR Suppression Pool Spray B 3.6.2.4 BASES SURVEILLANCE      SR 3.6.2.4,4 REQUIREMENTS (continued)    RHR Suppression Pool Spray System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and manag1ng gas intrusion and accumC:J1ation is necessary for proper operation of the RHR Suppr'essi on Pool Spray Subsystems* and may al so prevent water hammer and pumi;i cavitation.
Selection of RHR Suppression Pool Spray System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high po1nts and to conftrm the location and orientation of important compollents that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenahce or restoration. Susce~tible locations depend on plant and sys.tern configuration, such as stand-by versus operating conditions.
The RHR Suppression Pool Spray System is OPERABLE When it is I                            sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the a,cceptance criteria for the susceptible location (or the volume of accumy]Jlted__g,as at one or. mor~~e_p_:tible_
                        --~l~o-c-ations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the SR is met and past system OPERABILITY is evaluated under the Corrective Action Program. If tt is determi ne.d by subsequent evaluation that the. RHR Supp.ressi on Pool Spray System is not rendered inoperable by the accumulated gas (i.e., the sy.stem is sufficiently filled with water), the Surveillance may be declared met.
Accumulated gas should be eliminated or brought within the acceptapce criteria limits.
RHR Suppression Pool Spray System locations susceptible to gas accumulation a,re monitored. and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject .to the same gas intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods I                            (e.g., operating parameters, remote monitoring) may be used (continued)
PBAPS UNIT 2                        B 3..,6-63a.                  Revision No. 127
 
RHR Suppression Pool Spray B 3.6.2.4 I BASES SURVEILLANCE    SR  3,6.2,4.4  (continued)
REQU I RE'.MENTS to monitor the 5usceptible location. Mon1tortng is not required for susceptible 1ocations where the maximum potential .accumulated gas void volume has been eva1uated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible loca~iohs and trending of the results should be sufficient to assure system OPERABILITY during the Survei 11 ance interval.
The SR is modified by a Note. The Note recognizes that the scope of the surveillance is limited to the RHR system components. The HPSW system components bave been determined to not be required to be in the scope of this surveillance due to operating experience and the design of the system.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas I                  accumulation.
: 2. N.EDC-32988-A, Revis_ion 2, Technical Justification to Support Risk-Informed Modification to Selected Required End $tat~s for BWR Plants, December 2Q02.
I PBAPS  UNIT  2                  B 3.6-63b                    Revision No. 126 I
 
RHR Drywell Spray B 3.6.2.5 B 3.6  CONTAINMENT SYSTEMS B 3.6.2.5  Residual Heat Remoual (RHR) Drywell Spray BASES BACkGROUND          Drywell Spray is a mode of the RHR system which may be initiated under post accident condittons to reduce the temperature and pressure of the primary containment atmosphere. The Drywell Spray function 1s credited in design basis analyses to limit peak drywell temper.ature following a steam line break inside of the Drywell and may be used to mitjgate other loss of coolant accidents inside of the Drywell. This function is provided by two redundant Drywell Spray subs*ystems. Yhe purpose of this Lto is to ensure that both subsystems are OPERABLE in app7icab1e MODES.
Each of the RHR drywell spray subsystems contains two motor driven pu~ps, two heat exchangers and a heat exchanger cross-tie line, whi'ch are manually initiated and independently controlled. The two RHR drywell spray subsystems perform the drywell spray function by circulating water from the suppression pool through the RHR he[t exchangers and I
discharging the cooled suppression pool water into the drywell air space through the drywell spray sparger and spray nozzJ es. The spray then effects a temperature an.cl pressure-redu.cti on through the combined effects of evaporative and convective cooling, depending on the drywell ~tmosphere. If
                ----the-atmosptrere-t-s-sup-ertTe,rted~-T'api"tJ-ercrporat4ve--ctmti-n-g ~ , - ~
p.roc:ess will ensue. If the environment in the. drywell is saturated, temperature and pressure will be reduced via a convective cooling process.
Each drywell spray sparger line is supplied by one independent RHR drywell spray subsystem. If required. a small portion of the spray flow can be directed to the suppression pool spray ~parger and spray nozzles. High Pressure Service Water, circulating through the tube side of the heat exchangers, exchanges heat with the suppression pool water on the shell side of the heat exchangers and discharges this heat to the external heat sink.
Eac:h drywel l spray sub-system is equi piped with a RHR heat exchanger cross-tie linej located downstream of each RHR pump discharge and upstream of each heat exchanger inlet, which allows ~ne RHR pump to be aligned to supply both RHR heat exchangers in the same subsystem to provide additional conta.inment heat removal capability when only one RHR pump ~s available. The RHR heat exchanger cross-tie is normally closed, and is assumed in the design basis analyses to be placed in service one h,our following a design basis ,accident or transient when insufficient electric power is available to operate two RHR pumps in a subsystem.
(continued)
PBAPS UN IT 2                            B 3.6-63c                      Revision N~. 126
 
RHR Drywell Spray B 3.6.2.5 BASES (continued)
APPLICABLE'.          Refere~ce 2 contains the results of analyses used to SAFETY ANAtYSES      predict primary containment pressure and temperature response foll owing a spectrum of srna l l steam line break sizes. Steam line breaks are the most limiting events for drywell temperature response, since steam has higher energy content than liquid. These analyses, with primary focus on the drywell temperature response. take credit for containment sprays and structural heat sinks 1n the drywell and the suppression pool airspace. These analyses demonstrate that, with credit for containment spray (drywell and suppression pool), drywell temperature is maintained within limits for Environmental Qualification (EQ) of equipment located in the drywell for the analyzed spectrum of small steam line breaks. The RHR Drywell Spray System satisfies Criterion 3 of the NRC Policy Statement.
LCD                  In the event of a small steam l ihe break in the dtywel l, a minimum of one RHR drywell spray subsystem is credited in the design analyses to mitigate the rise in drywell I
temperatur*e and pressure caused by the steam line break, and to ma1ntain the.primary containment peak temperature and
        .                        pressure below the design limits (Ref. 2). To ensure that these requirements are- met, two RHR drywell spray subsystems
---------~-----------<,-one--4n-each--+0op-)-mu-s-t-be-G/3E--R:A:B17:~l1:tn--power f NJm t ~ - -------
    -                            safety"related independent power supplies. Therefore, in the event of an accident. at least one subsystem is OPERABLE assuming the worst case single active failure. An RHR drywell spray subsystem is OPERABLE when one of the pumps, two heat exchangers in the same subsystem. the associated RHR heat exchanger cross-tie line, two HPSW. System pumps capable of providing cooling to the two heat exchangers and associated piping, valves, instrumentation, and controls are OPERABLE.
Management of gas voids is important to RHR Drywell Spray System OPERABILITY.
APflLICABI LITY      In MODES 1 1 2, and 3, a steam line break in the drywell could cause a rise in primary containment temperature and pressure. In MODES 4 and 5, the probability and consequences of steam line breaks are reduced due to the pressure and temperature limitations in these MODES.
Therefore, maintaining RHR drywell spray subsystems I          PBAPS UNIT 2 OPERABLE is not required in MODE 4 or 5.
B 3.6-63d (continued)
Revision No. 126
 
RHR Drywell Spray B 3.6.2.5 BASES (continued)
ACTIOKS With one RHR dryw~ll spray subsystem 1roperable, the inoperable subsystem must be restored to OPERABLE status with1 n 7 days. In th1 s Condition, the remaini n-g OPERABLE RHR drywell spray subsystem is adequate to mitigate the effects of a steam line break in the drywell. However, the overall reliabi1fty is reduced because a single fa:1lure in the OPERABLE subsystem could resu1: in :-equced ability to mitigate the temperature rise associated with a steam lir::e break in, the drywell, for wr.ich drywell sprays are credited. The 7 day Completion Time was chosen in J1ght of the redundant RHR drywell sptay caoabil1ties afforded by the OPERABLE subsystem a11d the low protrabi 11ty of a steam line break in the drywell occurring during this period.
The Comp 1 etion Time is ~Ddtfied by a note c~) for a one-time change that extends the 7-day Cornpletion Tirne to. 10 days four (4) times until December 31, 2021 to allow for
                    ~od1f1cations to the HPSW System. The compensatory me3sures identified 1n EGC License Amendment Reauest letter dated I
September 28, 2018 must be establis~ed and in effect~ This change also affects TS 3.6.2.3, 3.6.2.4, and 3.7.1.
Ll
                    -WH1i bot.h RHR drywell sp-ray subsystems i rioperabl e, at 1ea.st one suosystem w.ust be restored to OPERABLE sta~1,;s w1th1 n 8 hours. In this Condit.ion, there , s a su-bstanti al loss of the ab~1ity to mitigate th~ temperature rise as~QCJated w1tn a steam line break i ri tre drywe~ 1, for whi cl': ctrywe~ 1 sprays are credited. T~e 8 hour Completiori Time is based on this loss cf function and is considered acceptable due to the low prcbabil~ty of a steam line breaK i~ the drywell and because a1:ernative metrcds to remove tie3t from prinary containment are ava~:aJ:e.
c,1  and  t,2 If the i~ooeraD~e RHR drywe11 spray su~system(s) can1ot be restored to OPERABLE status wi tni r. the associated Completion Time, the plar.t must be broug~t to a MODE in which the LC0 does not apply. To achieve this status, the plant must be brought to at least MODE 3 withir 12 ~ours ancl MODE 4 with1ri 36 hours. The allowed Compl~t1ori Ti.mes are reasonable, based on operating experience, to reach the required plant ccndit1ons from full power cona1tions 111 an orderly manner and_ without chall e11gi ng plant systems.
(continued)
PBAPS UNIT 2                            e 3.6*63e                  Revision No. 151
 
EAF41i e RHR Drywell Spray B 3.6.2 .. 5 BASES (continued)
SURVEILLANCE        SR 3,6.2.5.1 RtQU IREMENTS Verifying the. correct a1i gnment for manua 1, powe,r operated, and automatic valves in the RHR drywell spray mode flow path provides assurance th[t t~e proper flow paths will exist for system operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nona,cci dent position provided it can be al 1gned to the accident position within the time assumed in the accident analysis, This is acceptable since the RHR drywel1 mode is manually initiated. This SR does not require any testfng or valve manipulation; rather, it involves verification. that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be 1nadvertently misaligned, sLLch as check valves.
The S11rveillance Frequency is controlled under the Surveillance Frequency Control Program .
* SR 3.6,2.5.2 This Surveillance is performed to verify that the spray
                --~no=z,,_,.z,__,_J~es__ar:e..J10.+/---0b s..t.J'.'2u..c-t e-el-a-R d-t-h*ff"l;*-f 1--ow-w ti *1-t-e-p"Y'O-vi ct ea- -- --~-
when required. The Survei1 lance Frequency is controlled under the Surveillance Fre,quency Control Program.
SR 3.6.2,5.3 Deleted (continued)
PBAPS UN IT 2                                                                                                  Revision No. 130
 
RHR D~ywell Spray B 3,6.2.5 BASES SURVEILLANCE  SR 3,6.2.5.4 REQUIREMENTS (continued)  RHR CTrywell Spray System piping and components have the potential to develop voids an,d pockets of entrained gases.
Preventing and managing gas intrusion and accumulation is netessary for proper o~eration of the RHR Drywell Spray systems and may also prevent water hammer and pump cavitation.
Selection of RHR Drywell Spray System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumerrtatioft drawings, isometric drawings, plan and elevation Qrawings, and calculation-s. The design review is supplemented by system walk- downs to validate the system high points and to confirm the loi::ation and orientation of important components that can become sources of gas or cou]d otherwise cause gas to be trapped or difficult to remove duti ng system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.
The RHR Drywell Spray System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are I
established for the volurne of accumulated gas at susceptH.lle locatio,ns. If accumulated gas is dis.covered that exceeds t he a cc ep ta nce c.*r i t er i a f or t he s us cept i bl e 7oc ati o,n ( or the vol um e of a cc um ul ~g_fil_:jl t_____o lle-0 r--m 0-r-e----s-tt-S--e e ptiir-h;.--------- - - --- -
~~~--------~-~-l-o-catttimexc;eed-s an acceptance criteria for gc1s volume at
                                                                                                                              ~
the suction or ctiScharge of a pump), the S~rveillance is not met. If the accumulated gas is eliminated or brought wtthin tne acceptance criteria 1 i mi ts during performance of th.e Surveillance, the SR is met and past system OPERABILITY is.
evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Drywell Spray System is not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water),
the Surveillance may be declared met. Accumulated gas should' be eliminated or brought within the acceptance criteria limits.
RHR Drywel 1 Spr.ay System l{)cati ons susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same ga~ intrusion mechanisms may be verified by monitoring a representative subset of susceptible locations. Nor:iitoring may not be practical for locations that are inaccessible due to radiological or environmental cond,itions, the plant configurfftion, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible locatiDn. Monitoring is not (continued)
PBAPS UNIT 2                              B 3.6-63g                                    Revision No. 127
 
RHR Drywell Spray B 3.6.2.5 BASES SURVEILLANCE      SR 3.6,2.5.4      (continued)
REQUIREMENTS required for susceptible locations where the maxtmum potential accumulated gas votd. volume has been evi:!1uated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.
The SR is modified by a Note. The Note recognizes that the scope of the surveil1ance*1s limited to the RHR system components. The HPSW system components have been determined to not be required to be in the scope of this surveilla~ce due to operating experfe~ce and the design of th.e system.
The Surveillance Frequency is controlled under the Sur\>eillance Frequency Control Program, The Surveillance Frequency may vary by location susceptible to gas accumulation.
REFERENCES        1. UFSAR, Sections 5.2. and 14.6.3.
                                                                      ....,___ .....-----.------- - -- ---- -~-- -
~----,_~- -- *- ~ --------z-: - ~ "ffEDf::-33566R--~*-;Safety Analysis Report for Exel on Peach Bottom Station Units 2 and 3, Constant Pressure Power Uprate" Revision O.
PBAl?S UNIT 2                          B 3.6-63h                                        Revfsion No. 126  I
 
CAD System B 3.6,3.1 B 3.6  CONTAINMENT SYSTEMS B 3.6.3.1  Deleted THE INFORMATIO.N FROM THIS TECHNICAL SPECIFICATIONS BASES SECTION HAS BUN DELETED. TECHNICAL SPECIPICATIONS BASES PAGES B 3.6-65 THROUGH B 3.6-69 HAVE. BEEN INTENTIONALLY OMITTED.
I I
PBAPS UN IT 2 B 3.6-64 Revision No. 80  /
 
Primary Containment Oxygen Concehtratton B 3.6.3.2 B 3.6  CONTAINMENT SYSTEMS B 3.6.3.'2  Primary Containment Oxygen Concentration BASES BACKGROUND          All nuclear reactors must be designed to withstand events that generate hydrogen either due to the zirconium met~l water reaction in the core or due to radioiysis. The primary method to control hydrogen 1s to 1nert the pri,mary containment. With th~ primary containment inert, that is, o~ygen concentration< 4.0 volume percent {v/o), a combustible mixture c~nnot be present in the primary conta1nment for any hyd~ogen concentration. The capability to inert the primary containment and rnainta1n oxygen
                      < 4.0 v/o works together with the Containment Atmospheric Dilution (CAD) System to provide redund,ant -and diverse methods to mitigate events that produce hydrogen. For example, an event that rapidly generates hydrogen from zirconium metal water reaction will result in excessive hydrpgen jn primary containment, but oxygen concentratton will remain< 4.0 v/o and no combustion can occur. Long I                      term generation of bot0 hydrogen and oxygen from radiolytic decomposition of water may eventually result in a combustible mixture in primary containment, except that the CAD System dilutes an__g__r_fJQO}Le,s_JJyJfr:o.g@-!l~a-00-e-x:-ygen--ga-s--es------- -
        --~--- -----cfaITer-ff1~n- they-can be produced from radi ol ysi s and again no combustion can occ.ur.- Th.is LCO ensures that oxygen concentration ooes not exceed 4.0 v/o during operation in the tpplicable conditions.
APPLICABLE          The Reference 1 calculations ass~me that th primary SAFETY ANALYSES      containment is inerted when a Design Basts Accident loss of cool ant accident occurs. Thus, the hydro.gen .assumed to be.
released to the primary containment as~ result of metal water reaction in the reactor core will not produce combustible gas mixtures i11 the primary containment.
Oxygen, which is subsequently generated by radiolytic decomposition of water. is di1uted and removed by the CAD System more rapidly than it is produced.
Primary containment oxygen concentrat'ion satisfies Criterion 2 of the NRC Policy Statement.
{continued)
PBAPS UNIT 2                          B 3.6-70                          Revisian    No_ Rn
 
Primary Containment Oxygen Concentration B 3.6.3.2 BASES (continued}
LCO              The primary contaiment OX)'gen concentration is maintained
                      < 4,0 v/o to ensure that an event that produces any amount of hydrogen does not result in a combustible mixture inside primary containment.
APPLICABILITY    The primary conta.inment oxygen concentration must be within the- specified limit when primary containment is inerted, except as allowed by the relaxations during startup and shutdown addressed below. The primary containment must be inert in MOOE I, since this is the condition with the hi,ghest .probability of a.n event that could produce hydrogen.
Inerting the pri,ary containment is an operational problem because it prevents containment access without an appropriate breathing apparatus. Therefore, the primary contaitunent is inerted as late as possible in the plant startup and de-inerted as soon as possible in the plant shutdown. As long as reactor .power is< 15% ~TP, the potential for an event that generates significant hydrogen is low and the primary containment need not be inert.
Furthermore, the probability of an event that generates I <
hydrogen occurring within the first 24 hours of a startup, or within the last 24 hours before a shutdQWn, is low enough that these *windows,,* when the primary containment is not i nerted, _i_tt!__a_ls_o.JustlfJecL--lhe-~4----haur--t-i me -peri-od-i s-a reason ab1e aJ1101mt of t 1111e to a11 ow p1ant personnel to perfona inerting or de-inerting.
ACTIONS          LI If oxygen concentration is i2:: 4.0 v/o at any time while operating in MODE 1, with the exception of the relaxations allowed during startup and shutdown, oxygen concentration must be restored to< 4.0 v/o within 24 hours. The 24 hour Completion Tie is allowed when oxygen concentration is
                      ~ 4.0 v/o because of the availability of other hydrogen mitigating systems (e.g., the CAD System) and the low probability and long duration of an event that would generate signi.ficant amounts of hydrogen occu,rring during th_i s period.                                *
(continued}
PBAPS UNIT 2                                                                  Revision No. 0
 
Primary Containment Oxygen Concentration B 3.6.3.2 I BASES ACTIONS        .B......1
(.continued)
If oxygen concentration cannot be restored to within limits within the required Completion T1me, the plant must be brought to a MODE in which the LCD does not apply.
* To ach1eve this status, power must be reduced to::;; 15% RTP within 8 hours. The 8 hour Completi6n Time is reasonable, based on operating experience, to reduce reactor power from full p.ower conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE    SR      3.6.3.2.l REQUIREMENTS The primary containment (drywell and suppression ch.amber) must be determined to be inert by verifying that oxygen concentration is< 4.0 v/o. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
R,EFERENCES      l.        UFSAR, Section 5. 2. 3. 9. 5.
I I PBAPS UN IT 2                          B 3.6-72                    Revision No. 86
 
Secondary Containment B 3.6.4.1 B 3.6  CONiAINMENT SYSTEMS
  ~ 3.6.4.1  Secondary Containment BASES BACKGROUND        The function of the secondary containment is to contain and hold up fission products that may leak from primary containment following a Design Basis Accident (OBA). In conjunction with operation of the Standby Gas Treatment (SGT) System and closure of certain valves whose lines penetrate the seconda,ry contai hment, the secondary containment is designed to reduce the activity level of the fission products prior to release to the environment and to isolate and contain fission products that are released during certain operations that take place inside primary containment, when primary containment is not required to be OPERABLE, or that take place outside primary containment.
The secondary containment is a structure that completely encloses the primary containment and those components that may be post~lated to contain primary system fluid. This I                  structure forms a contro1 volume that serves to hold up and dilute the fission products. It is possible for the press.ure in the control volume to rise relative, to the environmental pressure (e.g., due to pump and motor heat
            -~-~oad--.aci.dJTIDnSJ..___Jo_p_r:aY.e,nLg.[.QJ.filcL] eve] !;!Xfi 1trati on 1YlJJl~-- __
allowing the secondary containment to be designed as a conventional structure, the secondary containment requires support systems to maintain the control volume pressure at less than th& external pressure. Requirements for these systems are specified separately in LCO 3.6.4.2, "Secondary Containment Isolation Valves (SCIVs) ," and LCO 3.6.4.3, "Standby Gas Treatment (SGT)_ System.        M APPLICABLE        There are two principal accidents for which credit is taken SAFETY ANALYSES  for secondary containment OPERABIL.ITY. These are a loss of coolant accident (LOCA) (Ref. 1) and a fuel handling accident inside secondary containment (Ref. 2) involving RECENTLY IRRADIATED FUEL. The secondary containment performs no active function in response to each of these limiting events; (continued}
PBAPS UNIT 2                        B 3.6-73                              Revision No. 75
 
Secondary Containment B 3.6.4.1 I                        BASES APPLICAB'LE    however, its leak ti ghtnes.s is re qui red to enst:1te that fission SAFETY ANALYSES products entrapped within the secondary containment structure (continued)  wi7l be treated by the SGT System prior to ,di.schar,ge to the environment.
Secondary containment satisfies Criterion 3 of the NRC Policy Statement.
LCO            An (YPERABLE secondary containment provides a control volume into which fission products that leak from primary containment, or are released from the reactor coolant pressure boundary components located in secondary containment, can be processed prior to release to the              _
environment. For the secondary containment to be considered OPERABLE, it must have adequate leak tightness to ensure that the required vacuum tan be established and maintained.
APPLICABILITY  ln MODES l, 2, and 3, a LOCA could lead to a fission product release to primary cbntainment that leaks to secondary corita i nment. Therefore, secondary containment OPERABILITY is I                                    fequired during the same operating conditions that require primary containment OPERABILIIY.
In MODES 4 a"nd 5, the probability and CQnseguenhe..s..__o_f_tbe.,_ ___ "_____ _
  ---- ............... ~ - - ~-- ----- Li)eA-arereduced aOe~fnepressure andtemperature limitations in these MODES. Therefore, maintaining secondary containmert OPERABLE is not required in MODE 4 or 5, except for other situations for which significant releases of radioactive material can be postulated, such as during movement of RECENTLY IRRADIATED FUEL assemblies in the secondary containment. Howe~er, outside ground level hatches (hatches HIS through H19 and Torus room access hatch H33) may not be. opened during movement of irradiated fuel. This wi 11 maintain CR doses acceptable.
ACTIONS        AJ_
If secondary containment is inoperable, it must be restored to OPERABLE status within 4 hours. The 4 ho-ur Completion Time provides a period of time to ~orrect the problem that is commensurate, with the importance of maintaining secondary containment during MODES 1, 2, and 3. This time period also ensures that the probability of an ~ccident (requiring secondary containment OPERABILITY) occurrfng during peri'ods where secondary containment is inoperable is minimal.
I                    PBAPS L1NIT 2                      B 3.6-74                      Revision No. 145
 
Secondary Containment B 3.6.4.1 I        BASES ACTIONS          .ILl (continued)
If secondary containment cannot be restored to OPERABLE status within* the required Completion Time, the plant must be brol!ght to a M0:0&#xa3; in which the overall plant risk is m~nimized. To achieve this status, the plant must be brought to at least MODE 3 within 12' hours. Rema'lni'ng in the Applicability of the LCO is acceptable because the p1ant risk in MOOE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repai'rs to restore the system to OPERABLE status will be short. Howevet, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on oper&ting experience, to reach the required plant conditions from full power conditions in an o~derly manner and without challenging plant systems.
Ll I                          Movement of RECENTLY IRRADIATED FUEL assemblies in the secondary containment can be postulated to cause fission product release to the secondary containment. In such cases,
                  ~-----_t.he __seco.nda.r.y---e-0n-ta+nme-nt-i-s- tti-e--on ly ba rr1er toreleasf-cif-
- --- ~- ----- -            fission products to. the envi ronmen:t. Therefore, movement of RECENTLY IRRADIATED FUEL assemblies must be immediately suspended if the secor1dary containment is inoperable.
Suspension of these activities shall not preclude completing an action that involves moving a component to a safe position.
Required Action C.1 has beaen modified by a Note stahrig th-at LCD 3.0.3 is not applicable, since the movement of RECENTLY IRRADIATED FUEL can only be performed in MODES 4 and 5, (continued)
PBAPS UNIT 2'                            B 3 .. 6-75
 
  #A- ij :.-S:f!JCi:M mmP'tfi:it?t#-BIW:t1/4-$3/4k#iCZl~tt*~~~;:':~~~i@&#xa3;f{"~.
Secondary Cont ai riment B 3.6.4.1
'                      BASES  (Continued)
SURVEILLANCE REQUIREMENTS SR 3.6.4.1.1 Verifying that secondary containment equipment ha-frhes are closed ensures that the inf1ltratiori of outside air of such a magnitude as to prevent maintaintng the desired negative pressure does not occur and provides a*dequate assurat:1ce that exfi ltrati on from the secondary cont a, nment wil 1 not occur.
In thjs application, the term "sealed" has no connotation of leak tightness. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR 3,6.4.1.2 Verifying that one ~e.condary containment access door in each access opening is closed provides adequate assurance that exfiltration from the secondary containment will not occur. An access opening contains at least one inner and one outer door.
In some cases, secondary containment access openings are shared such that there are multiple inner or outer doors. The intent is to not breach the secondary containment, which is achieved by maintaining the inner or outer portion of the barrier closed.
SR 3. 6. 4 .1. 2 provides an exception to al 1ow brief, I                                        unintentional, simultaneous opening of both an inne~ and outer secondary containment acces.s door.
The Survei 11 ante Frequency 1s control leg__ unQfil....,tb.e_S,Ur1Le.1J.l a1;1ce- ~+- - - -- -
                - - - ~ - - - - - ~ ----F"r-equency---C-'Ontro1~*Prtrgrcim:-* - - - - - - - -
SR 3,6.4.1.3 a~d SR 3.6,4.1.4 The SGT System exhausts the secondary containment atmosphere to the environment through appropriate treatment equipment.
Each SGT subsystem is designed to draw down pressure in the secondary containment to~ 0.25 inche~ of vacuum water gauge ins 180 seconds and maintain pressure in the secondary containment at~ 0.25 inches o.f vacuum water gauge for 1 hour at a flow rates 10,500 cfm. To ensure that all fission products r'eleased to the secondary containment are treated, SR 3.6.4.1.3 and SR 3.6.4.1.4 verify that a pressure in the secondary containment that is less than the lowest postulated pressure eiternal to the secondary containm~nt boundary can rapidly be estaolished*and mai-ntained. When the SGT System is operating as designed, the establishment and maintenance of s~condary containment pressure cannot be accomplfshed if the secondary containment boundary is not intact.
Establishment of this pressure is confirmed by SR 3.6.4.1.3 which demonstrates tbat the secondary containment can be drawn down to ~ 0. 25, inches of vacuum water gauge in s 180 C
PBAPS UN IT 2                            B 3.6-76                          Revision No. 120
 
MMiWSPriS Secondary C0ntainment
                                                                                . B 3.6.4.1 BAStS SURVEILLANCE  SR 3.6.4.1.3 and $R 3.6.4,1.4      Ccontfn11ed)
REQUIREMENTS secontjs using one SGT subsystem. SR 3.6.4.1.4 demonstrates that the pressure in the secondary contafnment can be maintained~ 0.25 inches of vacuum water gauge for 1 hour using one SGT subsystem at a flow rates 10,500 cfm. The 1 hour test period allows secondary containment to be in thermal equilibrium at steady state conditions. The primary purpose of these SRs is to ensure secondary containment boundary integrity. Tne. secondary purpose of these SRs is to ens*ure that the SG'r subsystem being teste.d functions as d,esigned. There is a. Separate tCO with Surveillance Requirements which serves the primary purpose of ensuring OPERABLITY of the SGT System. The inoperability of a SGT subsystem does not necessarily constitute a iailure of these Surveillances relative to the secondary containment eJl?ERABIUTY. The Survei 11 a nee Frequency is control 1 ed under the Su:rvei 11 ance Frequency Control Program.
RE!'."ERENCES 1. UFSARj Section 14.6,3.
I                          2.
3.
UFSAR, Section 14.6.4.
NEDC-32988-A, Revision 2, Technical J.u.sJ:_lf_u:at.fon----to----~----
-----------------3uppoFt~RfsK-Informed Modification to Selected Required End States for BWR Plants, December 2002.
PBAPS UNIT 2                    B  3.6-77                    Revision No. 97
 
SCIVs B 3.6.4.2 B 3.6 CONiAINMENT SYSTEMS B 3.6.4.2  Secondary Containment Isolation Valves {SCIVs)
BASES BACKGROUND            The function of the SCIVs, in oombinat1on w1th other accident mitigation systems, is to Cbntrol riss1on product release during and following postulated Des1gn Basis Accidents {DBAs) {Refs. 1 and 2). Secondary containment isolation within the time limits specifif ed for those isolation valves designed to close automatically ensures that fission products that leak from primary containment following a DBA,. or that are released during certain operations when primary containment is not required ta be OPERABLE or take place outside primary containment, are maintained WI thin the secondary containment boundary.
The OPERABILITY requirements for SCIVs help ensure that an adequate secondary containment boundary is maintained during and after an accident by minimizing potential paths to the environment. These isolation devices consist of either I                      passive devices or active {automatic) devices. Hanual valves, de-activated automatic valves secured in their closed position {including check valves with flow through the valve ~ecured), and blind flanges are considered~s~~v~e~--
            -.---..-c~,devt-ce-s.
Automatic SCIVs close on a secondary containment isolation signal to establish a boundary for untreated radioactive material within secondqry containment following a DBA or other accidents ..
Other penetrati ans ,are i so1 ated by the use of valves in the closed position or blind flanges.
APPLICABLE            The SClVs must be OPERABLE to ensure the secondary SAFETY ANALYSES      containment barrier to fission product releases is established. The principal accidents for which the secondary containment boundary is required ar~ a loss -0f coolant accident {Ref. 1) arid a fuel handling accident ins-f de secondary containment (Ref. 2) involving RECENTLY IRRADIATED FUEL. The secondary conta1 nment performs no active function.
1n response to either of these limit1ng events, but the (continued)
PBAPS UNIT 2                            B 3.6-78                      Revision No. 75
 
SCIVs B 3.6.4.2 I      BASES APPLICABLE*      boundary established by SCIVs is required to ensure that SAFETY ANAL YS'ES leakage from the prfmary containment is processed by the (continued)    Standby Gas Treatment ( SGT) System before b,efng rel eased to t.he envi ronmerrt.
Maintaining SC!Vs OPERABLE with isolation times within limits ensures that fission products will remain trapped inside secondary containment so that they ~an be treated by the SGT System prior to discharge to the environment.
SCIVs satisfy Criterion 3 of the NRC Policy Statement.
LCO              ${IVs form a part of the secondary containment boundary.                        The SCIV safety function is related to control of offsite radiation releases resulting from DBAs.
The power operated automatic isolation valves are considered OPERABLE when their isolation times are within limits and the valves actuate on an automatic isolation signal. The valves covered by this LC0 along with their associated stroke 1
times, are listed in Reference 2.
I                      The no rm a l 1y cl os e d i s ola t i on v a l ve-s o r b1t nd' fl ang es a re considered OPERABLE when manual valves are closed or open in accordance with appropriate administrative controls, automatic SC IVs a re de- a ct iv a ted and secured i uh...e..ir_-c:_lo.s_.ed~pos.i.t..i.of'1/2---- - -
-~---------~-- - -~-ali1lo1Tffafla nges are in .place. These p.assive isolati.on valv~s or devices are listed in Reference 2.
APP LI CAB I UTY  In MODES 1, 2, and 3, a DBA could lead to a fission product release to the primary containment that leaks to the secondary conta'i nmer:it. Therefore, the OPERABUl:.TY of SC IVs is required.
In :MODES 4 and 5, the probability and consequences of these events are reduced due to pressure and temperature limitations in these M0D[S. Therefore, maintaining SCIVs OPERABLE is not required in MOOE 4 or 5, exc.ept for other situations under which significant radioactive releases can be postulat~d 1 such as during movement of RECENTLY IRRADIAT~D FUEL assemblies in the secondary containment. SCIVs are only required to be OPERABLE during OPDRVs or handling RECENTLY IRRADIATED FUEL. Moving irradiated fuel assemblies in the secondary containment may a.lso occur in MOD[S 1, 2, and 3.
( conU nued)
PBAPS UN IT 2                            B 3.6-79                                Revision No. 145
 
SCIVs B 3.6.4.2 BASES (continued)
ACTIONS            The ACTIONS are inodif1ed by three Notes. The first Note allows, penetration -flow paths to be unisolated
:Intermittently under administrative controls. These controls consist of stationing a dedicated operator, who is in continuous conaunication with the control ro011, at the controls of the 1sol at ion device. In this way,. the penetration can be rapidly isolated when a need for secondary containment isolation 1s indicated.
The second Note provides clarification that for the purpose of this LCO separate Condition entry is allowed for each penetration flow path. This is acceptable, since the
                    -Required Actions for each Condition provide appropriate compensatory actions for each inoperable SCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable SCIVs are governed by subsequent Condition entry and application of associatea Req~ired Actions.
The third Note ensures appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable SCIV.
* I                    A.I and A,2
                      ~,,..,...__--~~~::7-~-~-~-~----- - ~ - - - - - -
          - - - - i n the event that there are. one or more. penetration flow paths with one SCIV inoperable, the affected penetration flow path(s) must be isolated. The method of isolation must include the use of at least one. isolation barrier that cannot be adversely affected by a single active failure.
Isolation barriers that 1Reet this criterion are a closed and de-activated aut0111atic SCIV, a closed ,manual valve, and a blihd flange. For penetrations isolated in acco.rdance with Required Action A.l, t'he device used to isolate the penetration should be the closest available device to secondary containment. The Req~ired Action must be completed with.in the 8 hour Completion Time. The specified time period is reasonable consi.dering the time required to isolate the penetration, and the probab1lity of a OBA, wbich requires the SCIVs to close, occurring during this short time is very low.
For affected penetrations that have been isolated in accordance with Re'quired Action A. 1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that secondary (continued}
PBAPS UNIT 2                          B 3 .6-80                      Revision No. O
 
SCIVs B 3.6.4.2 I  BASES ACTIONS            A.I  and    A.2      (continued) containment penetrations req~ired to be isolated following an accidellt, but no longer capable of being automatically isolated, will be in the isolation position should an event occur. The Completion Time of once per 31 days is appropriate because the isolation devices are operated under admi ni strati ve centrals and the probabil it.Y o.f their misalignment is low. This Required Actioh does not require any testing or device manipulation. Rather, it involves verification that the affected penetration remains isolated.
Required Action A,2 is modified by two Notes. Note 1 applies to devices located in high radiation areas and allows them to be ve*rified closed by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to th~se areas is typically restricted. Note 2 applies to isolation dev1ces that are 1ocked. sealed, or otherwise secured in position and allows these devices to be verified closed by ~se of administrative means. Allowing verification by administrative means is considered ace::eptahle~ since the function of locking, sealing, or s~euring components is to ensure that these devices are not inadvertently repositioned. Therefore, the probability of misalignment,
              -------an c-e--tti ey--tta-v-e-b-e-e n-v-e M*fi-e:d--t o-b e i rI t II e-pr o p-e r-p anti-an-,----
i s low.
Ll With two SCIVs in one or more penetration flow paths inoperable, the affected penetration flow path must be isolated within 4 hours. The metho~ of isolation must include the use of at least one isolation barrier that cannot be adverse1y affected by a single active failure.
Isolation barriers that meet this criterion are. a closed and de-activated automatic valve, a closed manual valve, and a blind flange. The 4 hour Completion Time is reasonable considering the time required to isolate the penetration and the probability of a OBA, which requires the SCIVs to close, occurring during this .short time, is very lo.w.
The Condition has been modified by a Note stating that Co~dition Bis only applicable to penetration f1ow paths with two isolation valves. This clarifies that only Condition A is'entered if one SCIV is inoperab1e in each cf two penetratio~s.
(continued)
PBAPS UNIT 2                                  B 3.6-81                                  Revision No. 57
 
SC IVs B 3.6.4.2 BASES ACTIONS            C.l and C.2 (continued)
If any Required Action and associated Completion Time cannot be met, the pl~nt must be brought to a MODE in Which the LCD does not apply. To achieve this st~tus, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions ih an orderly manner and witho~t challenging plant systems .
                      .Q_J_
If any Required Action and associated Completibn Time are not met, the plant must be placed in a condition in which the LCO does not apply. If applicable, CORE ALTERATIONS a,nd the movement of RECENTLY IRRADIATED FUEL assemblies in the secondary containment must be i mmedi atel y suspended.
Suspe.nsion of this activity shall not pre,clude completion of movement of a component to a safe position.
Required Action D.l has been modified by a Not~ stating that LCO 3.0.3 is not appl:icab1e, since the movement o~C__EJ':HlY~------
---------~..I--RRAO-I-A+Hl----flfH---carr-urrty1:ie performed in MODES 4 and 5.
SURVHLLANCE        SR 3, 6 .A , 2, 1 REQUIREMENTS This SR verifies that each secondary containment m~nual isolation valve and blind flange that is not locked, sealed, or otherwise secured and is required to be closed during accident cond1tions is closed. The SR helps to ensure that post accident leakage of radioactive. fluids or gases o,ut.side of the secondary containment boundary is within design limits. This SR does not require any testing or valve manipulation. Rather, it involves verification that those SCIVs in secondary containment that ~re capable of being mi s po s it i one d a re i n t he co r re ct posit i on .
PBAPS UN IT 2                              B 3.6-8.2                        Revision No. 145
 
SCIVs B 3.6.4.2 BASES SURVEILLANCE  SR  3.6.4.2.I      (continued)
REQUIREMENTS Tbe Surveillance Frequency is controlled under the Surveillance Frequency Control Program. This SR does not appJ.y to valves that are locked, -sealed, or otherwise secured in the closE!d position, since these were verified to be in the correGt position upon locking, sealing, or securing.
Two Notes have been added to this SR. The first Note applies to valves and blind flanges loeated in high radiation areas and allows them to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, and 3 for AL.ARA reasons. Therefore, the probability of m:i~alignment of these SCIVs, once they have been verified to be in the prope~ position, is low.
A  second Note has been included to clarify that SCIVs that are open under administrative controls are not requi,red to I              meet the SR during the time the SCIVs a~e open.
SR  3.6.4.2.2 Verifying that the isolation time of each power operated automatic SCIV is within limits is required to demonstrate OPERAB!LITY. The isolation time test ensures that the SCIV will isolate in a time period .J,.ess than or equal '.::o that assumed in t])e safety analyses. The Frequency of thi~ SR is*
in accordance with che INSERVICE TESTING PROGRAM.
SR  3. 6. 4. 2-. 3 Verifying that each- automatic SClV clo_.ses on a secondary containment isolation signal is required to prevent leakage of radioactive material from secondary containment following a OBA ot other accidents. This SR ensures that each automatic SCIV will actuate to the isolation position on a secondary containment isolation signa_l. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment lsolation Instrumentation," overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency- is cor:trolJ.ed under the Surveillance Frequency Control Program.
(continued)
PBAPS UNIT' 2                      B 3.6-83                  Revision No. 140
 
SC IVs B 3.6.4.2 I BASES (continued)
REFERENCES        1. UFSAR, Section 14.9.2.
: 2. Technical Requirements Manua 1.
I PBAPS UNIT 2                    B 3.6-84            Revision No. 86
 
SGT System B 3.6.4.3 B 3,.6 CONTAINMENT SYSTEMS
' B 3.6.4.3 Standby Gas Treatment (SGT) System BASES BACKGROUND        The SGT System is required by UFSAR design criteria (ijef. I). The function of t~e SGT System is to ensure that radioactive materials that leak from the primary containment into the secondary conta i rnaent f o11 owing a Design Basis Accident (OBA) are filtered and adsorbed prior to exhausting to the environment.
A single SGT System is coRIDOn to both Unit 2 and Unit 3 and consists of two fully redundant subsystems, each with its own set of ductwork, dampers, valves, charcoal filter train, and controls. Both SGT subsystems share a c0111DOn inlet plenum. This inlet plenum is connected to the refueling floor ventilation exhaust duct for each Unit and to the suppression chamber and drywell of each Unit. Both SGT subsystems exhaust to the plant offgas stack through a comon exhaust duct served by three 10~ capacity system fans. SGT System fans OAV020 and OBV020 automat ieally start on Unit 2 secondary c:ontaimlij!nt isolation signals. SGT System fans OCV020 and OBV020 automatically start on Unit 3 secondary containment isolation signals.
Each charcoal filter train consists of (components listed in order of the direction of the air fl ow)~*
: a. A demister or moisture separator;
: b. An electric heater;
: c. A pref11 ter;
: d. A high efficiency particulate air (HEPA) filter;
: e. A charcoal adsorber; and f .. A second HEPA f i l te.r.
The SGT System is sized such that each IO~ capacity fan will provide a flow. rate of 10,500 cfm at 20 inches water gauge static pressure to support the control of fission product releases. The SGT System is designed to restore and maintain secondary contai*nment at a negative pressure of 0.25 inches water gauge relat1ve to'the atmosphe.re foll'owing (continued}
PBAPS UNIT 2                                                        Revision No. o
 
SGT System B 3.6.4.3 BASES BACKGROUND        the receipt of a secondary containment isolation signal.
(continued)    Maintaining thts negative pressure is based upon the existence of calm wind conditions (up to 5 mph), a maximum SGT System flow rate of 10,500 cfm, outside air temperature of gs*F and a tellJ)erature of 1so*F for air entertng the SGT System from. inside secondary containment.
The demister is provided to remove entrained water in the air, while the electric heater reduces the relative humidity of the airstream 'to less than 70% (Ref. 2). The prefilter removes large particulate n:iatter, while the HEPA filter removes fine part kul ate matter and protects the charcoal from fouling. The charcoal adsorber removes gaseous elemental iodine and organic iodides, and the final HEPA .
filter collects any carbon fines exhausted fr011 the charcoal adsorber.
The SGT System automatically starts and operates in response to actuation signals indicative of conditions or an accident that could require operation of the system. Following initiation, two charcoal filter train fans (OAV020 and 0BV020) start. lfpon verification that both subsystems are operating, the redundant subsystem is normall~ shut down.
_ _ _ _,_....Aee.LICABU  -~T.he-desi gn-bas-i s---ro~e ...SGl-Sy-s-tem--ls--ti>~mH:-i gate-the-- -- - * -- - -
SAFETY ANALYSES consequences of a loss of coolant ac::ctdent and fuel handling accidents (Ref. 2). For all events analyzed, the. SGT System is shown to be automatically initiated to reduce, via filtration and. adsorption, the radioactive materi.al released to the environment.
The SGT System satisfies Criterion 3 of the NRC Policy Statement.
LCO                Following a DBA, a minimum of one SGT subsystem is required to maintain the secondary conta:lrunent at a negative pressure with respect to the environment and to process gaseous
                            ,releases. Meeting the LCO requirements for two OPERABLE subsystems ensures operation of at least one SGT subsystem in the event of a .single active failure.
(continued)
PBAPS UNIT 2                          B 3.6-86                              Re.vision No. 0
 
SGT System I
B 3. 6. 4 .. 3 BASES LCO            For Unft 2, one SGT subsystem is OPERABLE when one charcoal
    <continl}ed) filter train, one fan (OAV020) and associated ductwork, dampers, valves, and controls are OPERABLE. The second SGT subsystem is OPERABLE when the other charcoal fiHer trairi, one fan (0BV020) and associated ductwork. damper, valves, and controls are OPERABLE.
APPLICABILITY  In MODES 1, 2, and 3, a ~BA could lead to a fission product release to primary containment that leaks to secondary containment. Therefore. SGT System OPERABILITY is required during these MODES.
In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the SGT System in ongABLE status is not required in MOOE 4 or 5 1 except for other situations under which significant releases 0f radioactive material can be postulated, such as during movement of RECENTLY IRRADIATED FUEL assemblie.s in the secondary containment, The SGT System is only required to be OPERABLE during 0PDRVs or handling of RECENTLY IRRADIATED I
FUEL.
ACTl 0NS      Ll With one SGT subsystem inoperable, the in-Operable subsystem must be restored to-OPERABLE status in 7 days. In this Condition, the remaining OPERABLE SGT subsystem is adequate to perform the required radioactivity release control function. Howev-er, the overall system reliability is reduced because a single filflur.e in the OPERABLE subsystem could result in the radi cacti vi ty rel ease control fun-cti on not being adequately performed. The 7 day Completion Time is based on consideration of such factors as the availability of the OPERABLE redundant SGT subsystem and the low probaoiltty of a DBA occurring during this period.
LI If the SGT subsystem cann'ot be restored to OPERABLE status within the required Completion Time in MODE 1, ~. or 3, the pl ant must be brought to a MOOE 1n which the overall pl a.nt risk is minimized. To achi~ve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the I PBAPS UN.IT 2                    8 3,.6-87                    Revision No. 145
 
SGT System I
B 3.. 6.4.3 BASES ACTIONS      .B....J. (continuetl).
Ap~licability of the LCO is acceptable because the plant risk in MODE 3 ts similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry itito MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experi'ence, to reach the re.qvi red pl ant conditions from full power conditions in an orderly manner and without ch.allengir\g plant systems.
c.1 and c.2,2 During movement of RECENTLY IRRADIATED FUEL assembJies, in the secondary containment when Required A.ction .A.1 cannot be completed within the required Completion Time, the OPERABLE
                .SGT subsystem shou.ld immediately be placed in operation. ihis I                action ensures that tne remaining subsystem is OPERABLE, that no failures that could prevent automatic actuation have occurred, and that any other failure would be readily detected.                        --~ --~---------~--
An alternative to Required Action. C.1 is to-immediately suspend activities that represent a potential for releasing radioactive material to the secondary containment, thus placing the plant in a conaition that minimizes ri.sk. If applicable, movement of RECENTLY IRRADIATED FUEL assemblies must immediately be suspended. Suspension of this activity must not p'reCl ude comp 1eti on of movement of a component to a s af e po s it i on_.
The Requtred Actions of Condition C have been modified by a Note stat1ng that LCO 3.0.3 is not applicable. since the movement of RECENTLY IRRADIATED FUEL can only be performed in MODES 4 and 5.
PBAPS UNIT 2                        B 3.6-88                  Revision No. 145
 
SGT System B 3.6.4.3 I BASE$
ACTIONS        Ll (continued)
If both SGT subsystems are inoperable in MODE 1, 2, or 3, the SGT System may not be capable of supporting the required radioactivity release control function. Therefore, the plant must be brought to a MO.DE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (.Ref. 3) and because the time spent in MODE 3 to perform the necessary ~epairs to restore the s.ystem to OPfRABLE status wi 11 be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonab 1e, based on operating ex.peri ence, to reach th.e required plant conditions from full power conditions in an orderly manner a-nd without <;haJlengtng plant systems.
Ll When two SGT su"bsystems. are inoperable, 1f applicable, movement of RECENTLY IRRADIATED FUEL assemblies in secondary I                containment must immediately be suspended. Suspension of this activity shall not preclude completion qf movement of a component to a safe position.
      - ~ ~---lte r:J l.t'l-re&-A-ctto rr-r.t-tras-t:re-e-n:-mutrffTecloya7fo te .stat i ng that LCO 3.0.3 is not apRlicable, ~ince the movement of RECENTLY IRRADIATED FUEL can only be performed in MODES 4 an_d 5.
SURVEILLANCE  SR    3.6.4,3.1 REQUIREMENTS Operating each SGT subsystem (including each fi1ter train fan) for
                ~  15 minutes ensures that both subsystems are OPERABLE and that all associated controls are functioning prop,erly. rt also ensures that bloGkage, fan or motor failure, or excessive vibration can be detected for corrective action. Operation with the heaters on (automatic heater cycling to maintain temperature) for
                ~ 15 minutes periodically is sufficient to eliminate moisture on the adsorbers and HEPA filters since during idle p~rfods instrument air is injected into the filter plenum to keep the filters dry. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
PB.APS UNIT 2                                                              Revision No. 145
 
SGT System B 3.6.4.3 I BASES SUR VE IL LANCE  SR 3.6.4,3.2 REQUIREMENTS (continued)    This SR verifies that the required SGT filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations).
Specific test frequencies and additional information are discussed in detail in the VFTP.
SR 3.6.4.3.3 This SR verifies that each SGT subsystem starts on receipt of an actu,al or simulated initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6,2, "Secondary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. The survei,lance Frequency is controlled under the Surveillance Frequency Control Program ..
I REFERENCES      1.
              ~~- ~
UFSAR, Section 1.5.1.6.
l:l F-SA-R-,5-e cl-i-e n-t4-;--9-;--------
: 3. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Pl ants, December 2002.
PBAPS UN IT 2                                                    Revision No. 86
 
HPSW System B 3.7.1 I        B 3.7  PLANT SYSTEMS B 3.7.1 High Pressure Service Water CHPSW) System BASES BACKGROUND        The HPSW System 1s designed to provide cooling water for the Residual Heat Removal CRHR) System heat exchangers, required for a safe* reactor shutdown following a Design Basi-s Accident (OBA) or transient. The HPSW System is operated whenever the RHR heat exchangers are required to operate in the shutdown cooling mode or in the suppression pool cooling or spray mode of the RHR System.
The HP'SW System consists of two independent and redundant subsystems. Each ~ub~ystem is made up of a header, two 4500 gpm pumps, a suction source, valves, piping and associated instrumentation. Either of the two subsystems is capable of providing the required cooling capacity with one pump operating to maintain safe shutdown conditions. The two subsystems are separated from each other by a normally I
closed motor operated cross tie valve, so that failure of one subsystem will not affect the OPERABILITY of the other subsystem. The normally closed cross tie valve is supplied with redundant safety related power* supplies to ensure that
---------~~----a~s,_*n~g~le failur_e will not prev~t_it from bei_Jlg_Qpened whe.Jl_______~-
required during a design basis event. A line connecting the HPSW System of e.ach unit is also provided. Separation of the two units HPSW Systems is provided by a series of two locked closed, manually operated valves. The HPSW System is designed with sufficient redundancy so that no single active component failure can prevent it from achieving its design function. The HPSW System 1s described in the UFSAR, Section 10.7, Reference 1, Normal cooling water is pumped by the HPSW pumps from the Conowing.o Pond through the tube side of the RHR heat exchangers, and discharges to the discharge pond. The required level for the HPSW pumps in the pump bay of the pump structure is~ 98.5 ft Conowingo Datum (CD) and s 113 ft CD. The minimum level ensures net positive Sijct1on head and the maximum level corresponds to the level 1n the pump bay w1 th 'water solid up to the motor baseplate:. An alternate supply and discharge path (from the emergency heat s1nk) is available in the unl1kely eV'ent the Conowtngo dam fails or th,e pond f1oods. This lineup, however, has to be manually aligned.
(continued)
PBAPS UNIT 2                          B' 3,7-1                    Revision No. 114
 
HPSW System B 3.7.1 I BASES BACKGROUND        The system is fnitiated manually from the control room. If (continued)      operating during a loss of coolant accident CLOCA), the system is at1tomatica1ly tripped to allow the. diesel generators to automat i call y power only that equipment necessary to reflood the core. The system (using a single HPSW pump) is assumed in the analysis to be manually started 10 minutes after the LOCA. At one hour after the LOCA, a second HPSW ptJmp is assumed to be started, with the HP'SW cross tie line placed in service 1f required to provide cooling water to two RHR heat exchangers. The RHR System design permits the system to be in1tiated as early as 5 minutes after LPCI initiation.
APPUCABLE          The HPSW System removes heat from the suppression pool to SAFETY ANALYSES    limit the suppression pool temperature and primary containment pressure following a LOCA. This ensures that the primary containment can perform its function of limHing the release of radioactive materials to the environment following a LOCA. The ability ,of the HPSW System to support long term cooling of the reactor or primary containment is I                    discussed in References 2* and 3. r"hese analyses explicitly assume that the HPSW System wi Tl provide adequate cooling support to the equipment required for safe shutdown. These analyses include the evaluatio*n of the 1ong term primary
                ~~~containment response after a design ba_si s LQCA.
The safety analyses for long term cooling were performed for various combinations of RHR System failures. The worst case single failure that would affect the performance of the HPSW System is any failure that would disable one HPSW subsystem.
As discussed in the UFSAR, Section 14.6.3 (Ref. 4} for these analyses, manual initiation of the OPERABLE HPSW subsystem and the associated RHR System is assumed to occur 10 minutes after a OBA. Manual alignment of the HPSW cro~s tie is assumed at 1 hour after a OBA, with a failure of a single diesel generator, to ensure that two HPSW pumps are available to provide the required cooling flow to two RHR heat exchange rs within a *containment cooling/spray subsystem. Opening of the cross tie motor operated valve removes separation bet~een the two HPSW subsystems; however, because the cross ti~ valve is opened only after a single diesel generator failure has occurred, a~ additional faifure does not need to be considered. and independence of the two HPSW subsystems is not required following the DBA with a single diesel generator failure.
I                                                                            (continued)
PBA.PS UN IT 2                        B 3.7-2                      Revision No. 114
 
HPSW System I
B 3.7.1 BASES APPLICABLE      The HPSW flow asswned in the analyses is 4'500 gpm per pump SAFETY ANALYSES with two pumps 0perati ng providing fl ow through tlie two (conttnued)  required RHR heat exchangers. In this case, the maximum suppre.ssi on chamber water temperature and press.ure are less than or equal to r88&deg;F and 43 psig, respectively, well below tlie design temperature of .281 &deg;F and maximum al 1owabl e pressure of 56 psig.
The HPSW System satisfies Criterion 3 of the NRC Policy Statement.
lGO            Two HPSW subsystems and the HPSW cross tie line (which allows two HPSW subsystems within the same unit to be connected) are required to be OPERABLE to pro vi de the required re.dundancy to ensure that the system functions to remove post-accident heat loads, assuming the worst case single active failure occurs coincident w1tli the loss of offsite power.
Additionally, the HPSW cross tie valve (which allows the two HPSW subsystems to be connec*ted) must be closed so that fa 17 ure I                  of one subsystem will not affect the OPERABILITY of the other subsystems.
A HPSW subsystem is considered OPERABLE when:
: a. Two pumps are OPERABLE; and
: b. An OPERABLE flow path is capab1e of taking suction from the pump structure and transferring the water to the required RHR h~at exchan,ger at 'the assumed flow rate.
The HPSW cross tie is OPERABLE when:
: a. The HPSW cross tie va1ve is OPERABLE; and
: b. An OPERABLE flow path is capable of cross connecting or isolating the two HPSW subsystems. If the HPSW cross-tie valve is being cred1ted for considering a HPSW subsystem OPERABLE by usitlg one pump in each subsystem, then the other HPSW subsystem must be considered ~o be inoperable.
An adequate suction source is not addressed in this LCO since the minimum net positive suction head (98.5 ft Conowingo Datum (CD) in the pump bay) and normal heat sink temperature requirements are bounded by the emergency service water pump and. normal heat sink requirements (LCO 3.7.2, "Eme-rgency Ser'vice Water (ESW) System and Normal Heat Sink")..
(continued)
  , PB*APS UNIT 2:                      B 3.7-3                        Revision No. 144
 
+/-+W#f I    BASES  (continued)
HPSW System B 3.7.I APPUCABIUTY          In MODES 1, 2, and 3, the HPSW System is required to be OPERABLE to support the OPERAS! UTY of the RHR System for primary
                          . containment cooling (LCO 3.6.2.3, "Residual Heat Removal (RHR)
Suppression Pool Cooling,* and LCO 3.6.2.4, "Residual Heat Re:noval (RHR) Suppression Pool Spray") and decay heat removai
( LCO 3'. 4. 7, "Residua 1 Heat Removal ( RHR) Shutdown Coo 1i ng System-Hot Shutdown"). The Applicability 1s therefore consistent with the requirements of these systems.
In MODES 4 and 5, the OPERABILITY requirements of the HPSW sy,stem ate determined by the systems ii; supports, and therefo:--e, the reql!liremrrnts are not the same for all facets of operation iri MODES 4 and S'. 'rhus, tne l COs of the RHR shutdown coo 11 ng system, which requires portions of the HPSW System to be OPERABLE, will govern HPSW System operation in MODES 4 and 5.
ACTIONS              A..l With one HPSW subsystem 1noperable, the inoperable ~PSW subsystem must be restored to OPE:RABLt. statt.:s w1thin 7 days.
W:lth the Jn1t in th.is condition, the remaining OPERABLE HPSW I                          subsystem 1s adeq1.rnte to perform tt;ie HPSW heat removal function. However, the overall rel1ab1lity 1s reduced because a sin&#xa3;le failure in tne OPERAB:..E rlPS,W subsystem could result 1n loss of H?SW furctton. The Completio~ Time is based on the re.dunaant. HPSW ci!Pab1lities afu,.r_ce.d_i:>y-1he_ile.&#xa3;RABU--S-u0&-y.s..tern--~"~
                      -"ana!he low-probabiHty of an event occurring re*qui"ing HPS\./
du~ing this period.
The Reaut~ect Action is mcctified by a Note indicating t~at the apolicable Condit~o~s of LCO 3.4.7, be entered and Required Actions taken if an incperable H?SW subsystem results in an inoperable RHR shutdown cooling subsystem. This 1s an exception to LC3 3.0.6 and ensures the prcper actions are take~
for these cc~po~ents.
The Ccmpleticn Time is modifi.ed by a not!;? ('"") for a or.e-time.
change that extends the 7-day Co,mp:etion Tt:r,e to 10 days four (4) t1~es until QQcembe" 3i, 2021 to ailow fer modifications to the HPSW System. The comperJsatory measures ~dentHied in EGC License Amerdment Request {{letter dated|date=September 28, 2018|text=letter dated September 28, 2018}} must be established and in efect. Th1s ctiange also affects TS 3.6.2.3, 3.6.2,4, a~d 3.6.2.5.
With an inoperabls cross t 1 e line, the HPSW cross t~e liAe must be restored to an OPERASLE c;~atus within 7 days. With an inoperable HPS~ cross t 1 e line. ff no additional failures occur, and two HPSW st..bsyste:ns are OPERABLE, then the. two OPERABLE pumps and flow paths ensure two HPSW pumps are available to I  PBAPS UN !.T 2 (continued)
Revision No. 151
 
Watt I  BASES tlPSW System B 3.7.1 ACTIONS        LI      (continued)
* proviae adequate neat removal capac1ty following a ctes1gn basis accident. However, the. overall rel1abi1tty is reduced because a single failure in the HPSW system cou,d result 1h a loss of HPSW System functton. Therefore, continued operation ts permitted only for a lim1ted time. The Completion Ti e is based on remaining neat removal capacity, and the low probability of a OBA occurring during tMs perioc.
The Cow.pletion Time 1s modjfied by a ~ote (*) for a one-time c:hange 'that exte~ds the 7-day Completion Time to 10 days fo:Jr (4) times unt11 December 31, 2021 to all ow for modifications to the HPSW System. The tompens.atory fllasures identified in EGC License Amendment Request letter dated Se~tember 28, 2018 mLlst be establis'1ed a:id in effect. This change also affe.cts TS 3,6.2.3, 3.6.2.'1, and 3.6.2.5 .
                  .Ll if one HPSW subsystem or the HPSW cross tie 1s tnoperabTe and not restored ~ith1n the provideu Completion Time, tne pl2nt must I                  be brought to a condition 1n which the overall plant risk is minimized. To achieve this status, the plc!11t must oe brought to at le~st MOOE 3 ~ithin 12 ~ours. Remain111g in the AJplicability of the LCO is acceptable because the plant risk in MOOE 3 is s i mil c r :t.o_pr_J.Q.l,(e_t_j;h.a t i he_r~i ~ O D 5--4---(-Re-f-.-~ -) -.a-fl ct:- beea us,:;;--~-
th e. time spent in MODE 3 to perform the necessary repai r.s to restore the system to OPERABLE status wi 11 be srort. Howev,er, voluntary entry into MOaE 4 may be made as it is also an acceptable low-r1sk state. The allo~ed Coo:pletion Ti~e is reasonable, based o~ operating exoerience. to reach the required plant conditions from fu11 power conditions in an  "derly manner and without challenging p.l ant systemS' .
                  .D....l Wi':h both HPSW s.:bsystems inopel'cble~ the H?SW System is no~
Cgpable of perfor ing its intended funct~or.. At least one subsysten: must be restored to OPERABLE status with~n 8 hours.
The 8 hour Comoletion Ti~ for restoring one HPSW subsysteTil to CPERABLE status, is based on the Corn~le:ion r*m~s provided fer the'RHR suppression pool cocling and spray funct1ons.
Tne Required Actior. is modified by a Note 1nd~cating that the applicable Cond1tions o-F LCO .3.4.7, be entered and .Required Actions taken if ar. ~nopercrble HPSW subsystem results in an inoperable RHR shutdown cooling subsystem. This is an excepti.on to LCO 3.0.6 and en5ures the proper actions are taken for these components.
(contfriued)
I  PBAPS !JNIT 2                                B 3.7-5                              Revision ~o. 151
 
HPSW System B 3.7.1 I            BASES ACTIONS                E. l and E. 2
( cont1 nu*ed)
If the HPSW subsystems cannot be restored to OPERABLE status wfthin the assocfated Completion Time of Cond1tion D, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 12 hours and in MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power cond~tions in an orderly manner and without challenging unit systems.
SURVEI LLANGE        *sR 3,7,1.1 REQUIREMENTS Verifying the corre.ct alignment for each manual and power operated valve in each HPSW subsystem flow path provfdes assurance that the proper flow paths will exist for HPSW ope,ration. This SR does not apply to valve.s that are locked, sealeu. or otherwise secured in position, since these valves are verified to be fn the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet considered in the correct I                                    position, provided it can be realigned to its accident position. This is acceptable because the HPSW System is a manually initiated system.
- - - - - - ~ - - - - - - - -~-I,...,_bis___5.ILd.oes_noL_r...equ.-ire-any---.-ta.sU-ng--0r~v.a-l-ve-man*i ptfra-t-i cm; ---~--
rather, it involves ~erification that those valves capable of being misposttioned are in the correct ,position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.
The SurveiJlance frequency is controlled under the Surveillance Frequency Control Program.
SR 3,7,1.2 Verification of manual transfer between the normal and alternate power source (4kV em~rgency bus) for the HPSW cross~tie motor-oper~ted valve and each RHR heat exchanger HPSW outlet valve demonstrates that AC power will be available to operate the valves following loss of power to any single 4kV emergency bus.
The ability to provide power to the HPSW cross-tie valve and each RHR heat exchanger HPSW outlet valve from efther of two independent 4kV emergency buses ensures that a single failure of a DG will not resu1t 1n failure of a required HPSW System fl ow path; therefore, f.ai lure of the manual transfer capabi 1i ty will result in inoperabil1ty of the associated HPSW subsystem.
The Surveillance *Frequency is control lea under the Surve-i l lance I                                    Frequency Control Program.
(continued)
PBAPS UN IT 2                                  B 3.7-Sa                                Revision No. 114
 
HPSW System B 3.7.1 BASES  (continued)
REFERENCES          1. UFSAR, Section lQ,7.
: 2. UFSAR, Chapter 14.
: 3. NEDC-33566P, "Safety Analysis Report for Exelon Peach Bottom Atomic Power Station, Units 2 and 3, Constant Pre.ssure, Power Uprate," Revision 0.
: 4. UFSAR, Section 14.6.3.
: 5. NEDC-32988*A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
I f>BAPS UN IT 2                        B 3.7-Sb                  Revfsion No. 114
 
ESW System and Nonnal Heat Sink B 3.* 7 *. 2 B 3.7 PLANT SYSTEMS
'  B 3.7.2 Emergency Service Water (ESW) System and Normal Heat Sink BASES BACKGROUND      The ESW System is a standby system which is shared between Units 2 and 3. It is designed to provid~ cooling water for the removal of heat from equiJ)lllent, such as the diesel .
generators (DGs) and room coolers for Emergency Core Cooling System equipment, required for a safe reactor shutdown following a Design Basis Accident (DBA) or transient. Upon receipt of a loss.of offsite power signal, or whenever any diesel generator is in operation, the ESW System will prov1 de coo ling water to its requ.i red 1oads.
The ESW System consists of two redundant subsystems. Each of the two ESW subsystems consist of a 100% capacity 8000 gpm pump, a suttion source, valves, piping and associated instrumentation. Either of the two subsystems is capable of providing the required cooling capacity to support the required systems for both units. Each subsystem provides coolant 1n separate piping to coltltlOn headers; one each for the DG *coolers, Unit 2 safeguard equipment coolers, and Unit 3 safeguard equipment coolers. The design is such that any single active failure wilT not affect the ESW                ~--~*
  -~--------.System-from-provi di ng-*coulant-u1-tl:ie requ 1 red 1oads. - - -
Cooling water is pumped from the normal heat sink (Conowingo Pond) v1a the pump structure bay by tbe ESW pumps to the essential c0111ponents. After removing heat from the components, the water is discharged to the discharge pond, or the emergency cool i ng towe.r in certain test al i ghments.
An alternate suction supply and discharg.e path (from the emergency heat sink) is available in the unlikely event the Conowingo dam fails or the pond floods. This lineup, however, has to be manually aligned.
APPLICABLE      Sufficient water inventory is available for all ESW System SAFETY ANALYSES  post LOCA cooling requirements for a 30 day period with no additional makeup water source available. The ability -0f the ESW System to support 1ong tenn coo 1 i ng of the reacto.r contai.nment fs assumed in evaluations of the equipment required for safe reactor shutdown presented in the UFSAR, Chapter 14 (Ref. 1). These analyses include the evaluation of the long term primary containment response after a design bas\s LOCA.
                                                                        <continued)
PBAPS UNIT 2                        B 3.7-6                      Revision No. 4
 
ESW System and Normal Heat Sink B 3,7.2
\  BASES APPtICABLE          The ability of the ESW System to provide adequate coo1ing to SAFETY ANALYSE&#xa3;    the identified safety equipment is an impljcit assumption (continued)      for the safety analyses evaluated in Reference 1. The ability to provide onsite emergency AC power is dependent on the ability of the ESW System to cool the 0Gs. The long term cooling capa.biT1t.Y of the RHR and core spray pumps is also dependent on the cooling provided by the ESW System.
ESW provides cooling to the HPCI and RC!C room coolers; however, cooling function is not required to support HPCI or RC!C System operability.
The ESW System, together with the Normal Heat Sink, satisfy Criterion 3 of the NRC Policy Statement.
_ The ESW subsy.stems a re i lldependent to the degree that each ESW pump has separate controls, power supplies, and the operatio.n of one does not depend on the other. I:11 the- event of a DBA, one subsystem of ESW is required to provide the minimum heat removal capability assumed in the safety I                      analysis for the system to which it supplies cooling water.
To ensure this requirement is met, two _subsystems of ESW must be OPERABLE. At least one subsystem will operate, if
                  -~---th e.___w_o,r_s t-- s ,i ng_:i e-a e--t+v e--4a-i -l-1:tr e-o cc tir-s-cc:rincl aem w, l11fn_e_____
loss of offsite power.
A subsystem is considered OPERABLE when it has an OPERABLE normal heat sink, one -OPERABLE pump, and a.n OPERABLE flow path capable of taking ~uction from the pump structure and transferring the water to the appropriate equtpment.
The OPERABILITY of the normal heat sfnk is based on having a minimum and maximum water ~evel in the pump bay of 98.5 ft Conowingo Datum (GD) and 113 ft CD respectively and a maximum water temperature Of 92&deg;F.                                                              *I The isolatio~ of the ESW System to components or systems may re_nder those components or systems inoperable, but does not affect the OPERABILITY of the ESW System.
APPLTCABI LITY      In MODES 1, 2, and 3, the ESW System and normal heat sink are required to be OPERABLE to support OPERABILITY of the equipment serviced by the ESW System.. Therefore, the ESW System and normal heat sink are required to ~e OPERABLE in the*se MODES.
G PBAPS UN IT 2                                        B 3.7-7                                      Revision No. 109
 
ESW System and Normal Heat Sink B 3.7.2 BASES
'  APPLICABILITY (cpntinued)
In MODES 4 and 5, the 0pERABI LITY requirements of ttle ESW System and normal heat sink are determined by the systems they support, and therefore the requirements are not the same for all fa,cets of operation in MODES 4 and 5. Thus, the LCOs of the systems supported by the ESW System and normal heat sink will govern ESW System and normal heat sink OPERABILITY requirements in MODES 4 and 5.
ACTIONS        Ll With one ESW subsystem inoperable, the ESW subsystem must be restored to OPERABLE status within 7 day.s. With the unit tn this condition. the remaining OPERABLE ESW subsystem is adequ~te to perform the heat removal function. However, the overall reliability is reduced because a single failure in the OPERABLE ESW subsystem could result in loss of ESW function.
The 7 day Completion Time is based on the redundant ESW System capabi.l it i es afforded by the OPERABLE subsystem, the 1ow probability of an event occurring during this time I                  period, and is consistent with the allowed Completion Trrne for re~toring an inoperable DG.
If the ESW System cannot be restored to OPERABLE status within the associated Completion Time, or both ESW subsystems are inoperable, or the normal heat sink is inoperable, the unit must be placed tn a MODE in which the LCO does *not i:lpp,1y. To achieve this status, the unit must be p1a c e d 1n a t 1e as t MOOf 3 w1t hi n 12 hour s a nd i n MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from fu 11 power conditions in an orderly manner and without challenging unit systems.
SURVEILLANCE    SR 3.7.2.1 REQ'U I REMENTS This SR verifies the water level in the pump bay of the pump structure to be sufficient for the proper operation of the ESW pumps (the pump's ability to meet the minimum flow rate and ijnticipatory actions required for flood conditions are considered in determining these 1imits). The Survei 11 ance I                Frequency is controlled under the Surveillance Frequency Control Program.
PBAPS UNIT 2                          B 3.7-8.                        Revision No. 109
 
ESW System and Normal Heat Sink B 3.7.2 BASES
'  SURVE IUANCE REQUIREMENTS (continued)
SR 3.7.2.2 Verification of the normal heat sink temperature ensures that the heat removal capability of the ESW and HPSW systems is within OBA analysis. The water temperature is determined by using instrument!t1on that averages multiple inputs that measure the normal heat sink temperature. The SurveillaRce Frequency is controlled under the Surveillance Frequency Control Program. AdditionalTy, to ensure that the 92&deg;F normal heat sink temperature is not exceeded, this surveillance requires hourly monitoring Of the normal heat sink when the temperature is greater than 90&deg;F. The once per h0.ur monitoring takes into consideration normal heat sink temperature vartations a.nd the increased monitoring frequency needed to ensure design basis assumptions and equipment HmHations are not exceeded in this condition.
SR    3,7.2,3 Verifying the correct alignment for each manual and power operated valve in each ESW subsystem flow path provides I              assurance that the pro~er flow paths will exist for ESW operation. This SR does not apply to valves th.at are locked, sealed, or otherwise secured in position, since tb e_s_e__v..alv e-S-We-P- --v..e-r-:i-F-i ec!---t l'.l-----b e-1-n -t h - e ~ T f o n - -
0
[Jr i o,r to focking, sealing, or securing. A val*ve is also allowed to be in the nonaccident position, and yet considered in the correct position, provided it can be automatically realigned to its accident position within the required time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.
Th.is SR is modified bY a Note indicating that isolation of the ESW System to components or systems may render th0se components or systems inoperable 1 but does not affect the OPERA&ILITY Of the ESW System. As such, when a11 ESW pumps, valves, and piping are OPERABLE, but a branch connection off the main header is isolated, the ESW System is still OPERABLE.
The Surveillance .Frequency is controlled under the Survei 11 ance Frequency Control Program.
C PBAPS UNIT 2                              B 3. 7-9                                          Revision No. 109
 
ESW System and Normal Heat Sink B 3.7.2 BASES SURVEILLANCE  SR  3.7.2.4 REQUIREMENTS
  , (continued) This SR verifies that the ESW System pumps wil1 automatically start to provi qe cooling water to the required safety related equipment during an accident event. This is demonstrated by the use of an actual or simulated initiation signal.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
REFERENCES    1. U_FSAR, Chapter 14.
: 2. NEDC-32988-A 1 Revision 2, Te,chnical Justification to Support Risk-Info.rmed Modification to Selected Required End States for BWR Plants, December 2002.
I PBAPS UN IT 2                    B 3.7-10                    R'evi si on No. 86
 
Emergency Heat Sink B 3.7.3 I B 3.7  PLANT SYSTEMS B 3.7.3 lmergency Heat Sink BASES BACkGROU,ND        The function of the emergency heat sink is to provide heat remov~l capability so that the Unit 2 and J reactors can be safely shutdown tn the event of the ~navailability of the normal heat si.nk (Conowi.ngo Pond). The emergency heat sink supports the dissipation of sensible and dec~y heat so that th.e two reactors can be shutdown when the normal heat sink is unavailable due to flooding or failure of the Conowingo dam. This function is provided via the Emergency Service Water (ESW} System and the High Pressure Service Water System (HPSW).
The emergency heat sink con.sists of an in.duced draft three cell cooling tower with an integral storage reservoir, three emergency cooling tower fans, two ESW booster pumps, valves, piping, and associated instrumentation. The emergency cooling tower, equipment, valves, and piping of the emergency heat siAk are designed in accordance with seismic Class I criteria. Standby power is provided to ensure the emergency heat sink is capable of operating during a loss of offsite power.
When the normal heat sink (Conowing0 Pond) is lost or when flooding occurs, sluice gates in the pump structure housing the ESW pumps and HPSW pumps are closed. Water is then provided' through two gravity fed l ine.s from the emergency heat sink reservoir into the ~ump structure pump bays. The ESW and HPSW pumps then pump tooling water to heat exchangers required to bring the Unit 2 and 3 reactors to safe shutdown conditions. Return water from the HPSW System flows directly to two of the three cells of the emergency cooling tower. Return water from the ESW System flows through one of the two ESW booster pumps and is pumped into one of the emergency cooling tower cells used by the HPSW System. This configuration allows for closed cycle operation of the ESW and HPSW Systems.
Sufficient capacity (3.55 million gallons of water) is available, when the minimum water level is 17 feet above the bottGm of the emergency .heat $ink reservoir, to support simultaneous shutdown of Untts 2 and 3 for 7 days without makeup water. After 7 days, makeup water will be provided from the Susquehanna fiver or from tank trucks.
~                                                                        (continued)
PBAPS UN IT 2                        B 3. 7-11                    Revision No. 67
 
Emergency Heat Sink B 3.7.3 ffASES (continued)
APPLICABLE        The emergency heat sink is required to support removal of SAFETY ANALYSES    heat from the Unit 2 and 3 reactors, primary containments 1 and other safety related equipment by providing a seismic Class I h~at sink for the ESW and HPSW Systems for shutdown of the reactors when the normal non-safety grade heat sink (Conowing,o Pond) is. unavailable. Sufficient water inventory is available to supply all the ESW and HPSW System cooling requirements of both units during shutdown with a concurrent loss Of offsite power for a 7 day period with no additional makeup water available. The ability of the emergency heat sink to support the shutdown of both Units 2 and 3 in the event of the loss of the normal heat sink is presented in the UFSAR (Ref. 1).
The Emergency Heat Sink satisfies Criterion 3 of the NRC Po1icy Statement.
In the event the normal heat sink is unavailable and offsite power is lost, the emergency heat .sink is required to provide the minimum heat removal capability for the ESW and HPSW Systems to safely shutdown both units. To ensure this requirement is met, the emergency h,eat sink must be 1
OPERABLE.
                  -Tfleem erg en cj-neaTsTnR _B_cons i ct ere oar Ernl.: r-m nTt--z---t--
when it has an OPERABLE flow path from the ESW Sy.stern with one OPERABLE ESW booster pump, an OPERABLE flow path from the Unit 2 HPSW System, two of the three cooling tower cells and two of the three associated fans OPERABLE, one OPERABLE gravity feed line from the emergency heat sink reserv-0ir into the pump structure bays with the capability to connect the Unit 2 and 3 pump structure bays. or one OPERABLE gravity feed line from the emergency heat sink to the Unit 2 pump structure bay with the Unit 2 and Unit 3 bays not connected, and the capability exists to manually isolate the ESW and HPSW pump structure bays from the Conowingo Pond.
Valves in the required flow paths are considered OPERABLE if they can be manu.ally aligned to their correct position. The OPERABILITY of the emergency heat sink also requires a mini mum water 1evel in the emergency neat sink reservoir of 17 feet.
PBAPS UN IT 2                        B 3.7-12                          Revision No, 92
 
Emergency Heat Sink B 3.7.3 I  BASES LCO                Emergency heat sink water temperature is not addressed in (continued)      this LCO since the maximum water temperature of the emergency co-0ling tower rese~voir has been demonstrated, based on historical data, to be bounded by the normal heat sink requirements (LCO 3.7.2, "Emergency Service Water (ESW)
System and Normal Heat Sink").
  .APPLICABILITY      In MODES 1, 2, ~nd 3, the emergency heat sink is required to be OPERABLE to provide a seismic Class I source of cooling water to the ESW and HPSW Systems when the normal heat sink is unava.ilable. Therefore, the emergency heat sink is required to be OPERABLE in these MODES.
In MODES 4 and 5, the OPERABILITY requirements of the emergency he:at sink are determined by the systems it supports in the event the normal heat sink is unavailable.
ACTIONS            Ll.
With one required emergency cooling tower fan inoperable, action must be taken to restore the required emergency
'                    cooling tower fan to OPERABLE status within 14 days. The 14 day Completion Time is based on the remaintng heat removal
                ---capabT11 ty, ffie 7 ow proba15TlTlyofari event occiifrTng requiring the inoperable emergency cooing tower fan to function, and the capability of the remaining emergency cooling tower fan.
Ll With the emergency h~<lt sink inoperable for reasons other than Condition A, the emergency heat sink must be restored to OPERABLE status within 7 days. With the unit in this condition, the normal heat sink (Con.owingo Pond) is adequate to perform the heat removal function; however, the overall reliability is reducd. The 7 day Corilple.tion Time is based on the remaining heat removal capab1lity and the low probability of an event occurring requiring the emergency heat sink to be OPERABLE during this time period.
C I
PBAPS UN IT 2                          B. 3.7-13                    Revision No. 1
 
Emergency Heat Sink B 3,7.3 BASES ACTIONS            C,l and C,2 (continued)
If the emergency heat sink cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MOOE in which the LCD does not apply. To achieve this status, the unit must be placed in at least MODE 3 withi'n 12 hours and in MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required Unjt conditions from full power conditions in an orderly manner an-0 without challenging unit systems.
SURVEILLANCE        SR  3.7,3,1 REQUIREMENTS This SR ensures adequate long term (7 days) cooling can be
                      ~aintained in the event of flooding or loss of the Conowingo Pond. With the emergency heat sink water source below the minimum level, the emergency ~eat sink must be declared inop~rable. The Surveillance FreQuency is controlled u~der the Surveillance Frequency Control Program.
SR  3,7,'3,2
            ---~ - -ep-e-rcrt-tng-e*at h----req trt-redr-enre-rgen cy-*c-o o--1--i ng--t--owe r-f-a*n--f o~ - - ~ - -
                      ~ 15 minutes ensures that all required fans are OPERABLE and that a1l associated controls are functioning properly. It also ensures that fan or motor failure, or excessive vibration, can be detected for corrective action. The surveillance Frequency is controlled under the Surveillance Frequency Control Program.
REFERENCE$          1. UFSAR, Section 10.24.
PBAPS UN IT 2                                B 3.7-14                                      Revision No. 86
 
MCREV Syst,em B 3~7.4 I B 3.7  PLANT SYSTEMS B 3.7.4 Main Control Room Emergency Vent11ation (MCREV) System BASES BACKGROUND        The MCREV System provides a protected environment from which o.ccupants can control the un~ t following an uncontrolled release of radioactivity, hazardous chemicals, or smoke.
The MCREV System consists of two independent and redundant high efficiency air filtration subsystems and two 100%
capacity emergency ventilation supply fans which supply and provide emergency treatment of outside supply air and a CRE boundary that limits the inleakage of unfiltered air. Each filtration subsystem consists of a high efficiency particulate i;lir (HE'PA) filter, an activated charcoal adsorber section, a second HEPA filter, and the associated
                  -~~uctw0rk, valves or dampers, doors, barriers and instrumentation. Either emergency ventilation supply fan can aper.ate 1n conjunction with either filtration subsystem.
HEPA filters remove particulate matter, whictl may be radioactive. The charcoal adsorbers provide a holdup period for gaseous iodine, allowing time for decay. A dry gas purge is provided to each MCREV subsystem during idle periods to prevent moisture accumulation in the filters.
                                                                      -------~-
The CH is the area within the confines of th.e 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 may encompass other non-critical areas to which other frequent pers6nnel access or continuous occupancy is not necessary in the. event of an accident. The CRE is protected during normal operation~ natural events, and accidents conditions. The CRE boundary is the combination of walls, floor, roof, ducting, dampers, doorsj penetrations and equipment that physically form the CRE.      The OP[RABILITY of the C.RE boundary must be maintained to ensure that the in leakage of unfiltered air into the CRE will not exceed the inleakage assumed in the licensing bases analyses of design basis accident ( DBA) wnsequences and chemical hazards to CRE occupants. Since the equipment required and the allowable inleakage is different f~r radiological and chemical events.
the CRE boundary distinguishes between the boundaries required for each event. The CRE and its boundaries are defined in the Control Room Envelop Habitability Program.
PBAPS UN IT 2                          B 3.7-15                    Revisfon No. 116
 
MCREV System B 3.7.4 I  BASES BACKGROUND          The MC REV System is a standby syste*m that 1s common to both (contini,red)  Unit 2 and Unit 3. The two MCREV subsystems must be OPERABLE 1{ conditions requiring f,fCR'EV System OPERABILITY exist in either Unit 2 or On1t 3. Upon recei~t of the inft1at1on signal(s*) (indicati've of* conditions that could result in rad1 ati Ofl expos.ure to CRE occupants), th.e MCREV System automqtically starts and pressurizes the CRE to minimize infiltration of contaminated air into the CRE. A system of dampers isolates the CRE alo.ng the radiological boundary, and outside air, taken in at the normal ventilation intake, 1s passed through one of the charcoal r
adsorber filter subsystems for removal of airborne radioactive particles. During normal control room ventilation system restoration following operatton of the MCREV system, the automatic initiation function of MCREV w11 l b,rtefly be sati sfted by ope.rator actions and control 1ect procedural step.s.
If all normal ventilation and ai~ conditioning were lost, the control room operator WoUl d initiate an emergency shutdown of non-essential equipment and lighting to reduce the heat I-generation to a minimum. Heat removal would be accomplished by conduction through the floors, ceilings, and walls to adjacent rooms and to the envirorament. Additionally, th.e MCREV System is desjgned to maintain a habitable envi'ronrnent
                    ~-n-..-.tbe-.C RE...-to.r.:___a---30 --dii.y---C0-1:it-:i-l=l_UQUS-OC--CUpa.i+cy----a.f-t.e r- a-DBA-- ~ - - -
w1 thout exceeding* 5 re_m tota1 effect1 ve do.se equ4 val ent (TED(). A s1ng1~ MCREV subsystem will pressurize the CRE relative to the external areas adjacent to the CRE rad1ologtcal boundary to minimize infiltration of air from all surrounding areas adJacent to the GRE radi'olog1cal boundary. MCREV ~ystem operatio,n 1n maintaining CRE habftabil ity 1s discussed i IT the UFSAR, Chapters 7, 10, and 12, (RefS. 1, 2, and 3, respectively).
APP.LI CAB LE      The ability of tne MCREV System to maintain the habitability SAFETY ANALYSES      af t,he CRE is an exp1icit assumption for the safety analyses presented in the UFSAR, Chapters 10 and 12 (Refs. 2 and 3, respectively). The MCRE'V System is assumed to operate fol1owing a DBA, as discussed in the UFSAR, Section 14.9 (Ref. 4). The radiological doses to ttte CRE occupants as a result of the v.arious DBAs are summarized iri Re,ference 4.
No s i ngl e act i ve o r pas s i ve el e ct r i: ca l fa il a re wil l ca us.e the loss of outside or recirculated air from the CRE.
PBAPS UNIT 2                                        B 3.7-16                                      Revfsjon No. 116
 
MCREV System B 3.7.4 I BASES APPLICABLE      The MCREV System provides protect~on from smoke or hazardous SAFETY ANALYSES  chemicals to the CRE occupants. A periodic offsite chemical (continued) survey, and procedu~es for controlling onsite chemicals, are essential elements of CRE protection against hazardous chemicals. The system design is based on low probability of offsite sources of toxic gas, based on a chemical survey of the surrounding areas. Those offsi'te sources of toxic gas with a gre'ater than low probabi. l ity a re evaluated in accordance with Regulatory Guide 1.78 (Ref. 10) Or Regulatory Guide 1.95 {Ref. 11) and determined to be acceptable for continued habitability. The offsite chem1cal survey is con~ucted periodically to determine any change of condition that may need to *be addressed; The onsi te chemi ca1 s a re controlled procedurally such that they do not affect CRE habitability adversely.
Although the MCREV system does not have a t0xic gas mode, eval uati ens have been performed _to as.sess the. impact of taxi c gas on control room habitability.      The evaluations have concluded that based on either the low probability of hazardous chemical events occurring or operator action to don Self Contained Breathing Apparatuses {SCBAs) and secure the control room ventilation, additional protection from offsite hazardous chemicals is not required. Only new chemicals or changes in quantities of chemicals identified as part of the chem1 ca 1 surveyilil be ana 1yzed fffrflier for con-rrorroom habitability purposes.
The MCREV System satisfies Criterion 3 of the NRC Polity Statement.
Leo            Two redundant subsystems of the MCREV System are required to be OPERABLE to ensure that at least one is available, if a single active failure disables the other subsystem. Total MCREV System failure, such as from a loss of both ventilation subsystems or from an inoperable CRE boundary, could result in exceeding a dose of 5 rem total effective dose equivalent (TEDE) to the CRE occupants in the event of a OBA or for toxic gas events, result in incapacitation of the CRE inhabitants.
Each MCREV subsystem is considered OPERABLE when the individua1 components necessary to limit CRE occupant radiation exposure are OPERABLE. A subsystem is considered OPERABLE when:
: a. Qne Fan is OPERABLE; (continued)
PBAPS UNIT 2                                                      Revision No. 116
 
MCREV Sy.stem I
B 3.7.4 BASES LCO            b. HEPA filter and charcoal adsorbers are not excessively
          ,continued)        restricting flow and *are capab1e of performin-g. their filtration fun ct i ens; and
: c. Ductw9rk, valves, and dampers are OPERABLE, and air.
flow can be maintained.
A subsystem may be considered vperable u*sing either the A or B fan combined with either the A or B Filter bank.
In order for the MCR'EV subsystem to be cons1dered OPTRABLE, tt:ie CRE radi,ological boundary must be maintained such that the CRE occupant dose fr-om the large r.actioactive release ct6es not exceed the Cij)culated dose in the licensing basis consequence analyses for QBAs.
fo order for the MCREV subsystem to b.e considered OPERABLE, Ure CRE boundaries must be maintained OPERABLE, including the integrity of the walls. floor*s, ce1lH1gs, and ductwork.
Temporary seals. may be use.ct to ntaintain the boundary. F'or hazardous chemical events, the CRE chemical bound.ary 1s OPERABLE when the. CRE occupants can be protected from hazarct.ous chemicals. The. in leakage limit for hazardous I
chemicais is defined and estab1ished in the hazardous cherni cal analyse.s (Ref. 12 and 13), If measured 1nl eakage is greater than the limit established in the analyses, or if a new haz.ardous chemical (not meeting th.e screening criteria of Reference 10 or Reference 11) or increased quantity of an
  - - - ~ - - - - ~ x t s ttn g-ch1:1111-ca1-1--s-ci-et-e--rmi,re-"C\ taeX'l stT th~tl'fe" -m*----* ,-* --
ch emi C'a l boundary is co*nsidered inoperable, unless comtinued hab1tabi11ty is evaluated as.being acceptable (Ref. 10, 11).
For smake events, the CRE boundarY is OPERABLE when the CRE occupants can be proteeted from smoke events external or internal ta the plant. F0r smoke events 1 no regulatory limtt exists for the amount of smoke a11owed in the CRE. However, if smoke enters the CRE such that mitigating actions ar-e required, the.n the CRE boundary is considered inoper-able..
The LCO is m0d1fied by a Note allowing the CRE bound_ary to be opened i ntermi ttentl y under admitii strati ve cantrol s.
This Note only appli1e.s to openings in the CRE boundary that can be rapidly restored ta: the design t.ondition, soch a.s doors~ hatches, floor plugs, and access panels. For entry and exit th rnl!lgh doors, the admi ni strati ve control of the opening is performe.d by the person (s) entering or exiting the area. For other ope.ni ngs, these controls shoul ct be proceduralized and consist of stationing a dedicated individual at the opening who 1s in continuous communication w-rth the operators in the CffE. Th.1s individua_l will have a method to rapidly close the opening and to restore the CRE boundar*y to a condition equivalent to tt,e design condition when a need for CRE i sol ati on is 1ndi cate.d.
(coritinued)
PBAPS UNIT .2                                                                Revi'sfon No. 121
 
MCREV System B 3.7.4 I        BASES    (continued)
APPLICABILITY      In MODES 1, 2, and 3, the MCREV System must be OPERABLE to ensure that ttie CRE will remain habitable during and following a DBA, since the DBA could l~ad to a fission product release.
In MODES 4 and 5, the probabi 1 i ty and consequ,ences of a OBA are reduced because of the pressure ahd temperature limitations in these MODES. Therefore, maintaining the MCREV System OPERABLE is not requtred in MODE 4 or 5, except:
: a. During CORE ALTERATIONS; ~nd
: b. During movement 0f irradiated fuel assemblies in the secondary containment.
ACTIONS            Ll With one MCREV subsystem inoperable, for reasons other than I                          an inoperable CRt boundary, the inoperable MCREV subsystem must be restored to OPERABLE status within 7 days. With the unit in this condition, the remaining OPERABLE MCREV subsystem is adequate to maintain control room temperature
- ~ - - - - -~--- ----.rn:l-to-p~nrrrrrrh-e--cm-1Rctrpant~otectl on funGti on,              *----
Howe*ver, the overal 1 rel i abi 1 ity is reduced because a failure in the OPERABLE subsystem could result in loss of the MCREV System function. The 7 day Completion Time is cased on the low probability of a OBA occurring during this time period, and that the rem~ining subsystem can provide the required capabilities.
B.l, B,2 and B.3 If the unfiltered inleakage of potentially contaminated air past a CRE boundary and into the CRE can result in CRE occupant radiological dose greater than the calculated dose of the licensing basis analyses of OBA consequences (allowed to be-up to 5 rem total effective dose equivalent (TEDE)),
or inadequate protection of CRE occup~nts from hazardous chemicals or smoke that have been licensed to occur, the CRE boundary is inoperable. Actions must be taken to restore an OPERABLE CRE boundary within 90 days.
I PBAPS UN IT 2                        B 3.7-17                        Revision No. 145
 
MCREV $ystem B 3.7.4 BASES ACTIONS            B.l, B,2 and B,3 (continued)
Dur1ng the period that the CRE boundary 1s considered inoperable, action must be initiated to implement mit1gating actions to lessen the effect on CRE occupa.nts fr.om the potential hazards of a radiological or chemical event or a challenge from smoke (Refs. 6, 7, 10 and 11}. Action mast ~e 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 OBA consequences, and that CRE occupants are protected from hazardous chemicals and
                                -smoke as required. These mitigating actions Ci .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 OBA o-ccurring during this time period, and the initiation of mitigating actions. The 90 d,ay completion T1me is reasonable based on the determi natton that the mit1 gating actions wi 11 ensure I                                protection of CRE oc.cup.ants- within analyzed limits while limiting the probability that CRE ~ccupants will have to implement protective measures that may adversely affect their ability to control the reactor and ma1ntain it in a safe
~ - - - - - - - - - - - - - s - h 1:.1'E-d-awn-eo nct--H+on--i n-th e--e v ent--o f-a-0 B-A-.-I--ria d--dtt 1u-n-;-- --the 90 day Completion 1,ime is a reaso,nable time to diagnose, plan and repair, and test most problems with the CRE boundary.
Ll In MODE lj 2, or 3, if the inoperable MCREV subsystem or the CRE boundary cannot be restored to OPERABLE status within the required Complet~on Time, the unit must be placed in a MODE that minimizes overall plant risk. To achieve this status, the unit must be placed in at least MODE 3 with1n 12 hours.
Remaining in the App1icability of the LCO is acceptable because the plant risk in MOOE 3 is similar to or lower than the risk in MODE 4 (Ref. 5) and because the t1me spent in MOOE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MOD!: 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonab~e. based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
PBAPS UNIT 2                                B 3.7-18                              Revision No. 116
 
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1 MCREV System B 3.7.4 I          BASES ACTIONS (continued) 0.1. 0.2.1 and 0.2.2 The Required Actions *Of Condi ti on D are modified by a Note indicating that LCO 3,0.3 does not apply. If moving irradiated fuel assemblies while in MODE 1, 2. or 3, the fuel movement is independent of reactor operations.
Therefore, inability to suspend movement of irradiated fuel ass~mblies is not sufficient reason to require a reactor shutdown.
During movement of irradtated fuel assemblies in the secondary containment, during CORE ALTERATIONSj if the inoperable MCREV subsystem cannot be restored to OPERABLE status within the required Completion Time, the OPERABLE MCREV subsystem may be placed in operation. This action ensures that the remaining subsystem is OPERABLE, that no failures that would prevent automatic actuatiora will occur, and that any active failure will be readily detected.
An  alternative to Required Action 0.1 is to immediately suspend activities that present a potential for releasing radioactfvity that might require isolation of the CRE. This places the unit tn a condition that minimizes the accident risk.
I                        If applicable, CORE ALTERATIO~S and movement of ir~adiated fuel assemblies in the secondary containment must be suspended immediately. Suspension of these activities shall not preclude completio~ of movement of a component to a safe
________ ______p.os...i...tiol'.l-~----    ~-- - ~~-  ~---~----          ~~-r Ll If both MCREV subsystems are inoperable in MODE 1, ,2, or 3 for reasons other than an inoperable CRE boundary (i~e.,
Condition B), the MCREV System may not be capable of performing the intended function. Therefore. the plant must be brought to a MODE in which the overall plant risk is minimtzed. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. Remaining in the Applicability of the LCD is acceptable because the plant risk in MODE 3 is simil~r to or lower than the risk in MODE 4 (Ref. 5) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE st,atus wi 11 be short. However, voluntary entry into MODE 4 may te made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant condit1ons from full power conditions in an orderly manner an~ without challenging plant systems.
I ,
PBAPS UNIT 2                            B 3 . .7-19            Revision No. 145
 
MCREV Sys.tern B :1.7.4 a          BASES ACTIONS (continued)
F.l and F,2 The Required Actions of Condition Fare modified by a ~ote indicating that LCO 3.Q.3 does not apply. If moving*
irradice1ted fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operat1ons. .
Thereiore, inability to suspend movement of irradiated fuel assemblies is not sufficfent reason to require a reactor shutdown.
During movement of irradiated fuel assemblies in the secondary containment, during CORE ,ALTERATIONS with two MCREV subsystems inoperable or with one or more MCREV subsystems inoperable due to an inoperable CRE boundary, action must 0e taken immediately to suspend activities that present a potential for releasing radioacttvity that might require isolation of the CRE. This places the unit 1n a condition that m1nimizes t'he accident risk .
1f appl, cable, CORE AL TE RATIONS and movement of irradiated fuel assemblies in the secondary containment must be suspended immediately. Suspension of these activities shall not preclude c,ompletion of movement of a component to a safe position.
I          SURVEILLANCE REQUIREMENTS SR 3,7.4.1 This SR verifies that a subsystem in a standby mode starts
~--*- -~---*--------or:i--d-ema-ne--aAe-e0At-:f-n~es---t opera-te--ftl*r~---l m'i-nut-e-s .
Standby systems should be checked periodically to ensure that they start and function properly. As the environmental and normal operating conditions of this system are not severe, testing each subsystem pe~iodically provides an adequate check on this system. The Surveillance Frequency is control.led under the Surveillance Frequency Control Program.
* SR 3.7.4.2 This SR verifies that the required MCREV testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and the physicgl properties of the activated charcoal (general use and following sp~cific operations).
Specific test frequencies and additional information are discussed in detail in the VFTP.
PBAPS UNIT 2                            B 3.7-20                        Revision No. 145
 
MGREV System B 3.7.4 I          BASES SURVEILLANCE        SR  3.7,4.3 RE'QUIREMENTS (cont1nued)      This SR ver1fies that on an actual or simulated initiation signal, each MCREV subsystem starts and operates. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.7.1.4 overlaps this SR to provide complete testing of the safety function. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR 3,7.4.4 This SR verifies the OPE"RABIUTY of the CRE boundary by testing for unfiltered air inleakage past the CRE boundary and into the CR!:. The details of the testing are specified 1n the Control Room Envelope Habitability Program.
The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of OBA consequences* 1 s no more than 5 rem whole body dose or 1ts equivalent to any part of U1e body and the CRE occupants are prote.cte.d from hazardous chenHcal s and smoke that have been licensed to occur. This SR verifies that the unfiltered air 1nleakage into the CRE through the radiological and chemical boundaries is no greater than the
-~---------~-~-----:,t,--,-1--=o-;-:-w rates as,sumed in the 'licensing basis" analyses of OBA
* consequences and control room habitabil Hy eva.1 uati ons for hazardous chemicals. When unfiltered air inleakage is greater than the assumed flow rate, Condit1on B must be e,ntered. Required Action 8.3 allows time to restore the CRE boundary to OPERABLE status p,rovided mit.1gating actions can ensure that the CRE remains w1th1n the licens1ng basis habitab1lity limits for the occupants following an accident.
Mitigating actions are discussed 1 n Regal atory Gui de 1.196, Section C.2.7.3, (Ref, 6) which endorses, wfth exceptions, NEI 99-03, Section 8.4 and Appendix F (Ref. 7). These mitigating actions may also be used as mitigating actions as required by Required Action B,2. Temporary analytical methods may also be used as compensatory measures to restore O'PERABIUTY (Ref. 9). Options for restor1ng the CRE boundary to OPERABLE. status include chang1ng the licensing basis OBA consequence or chemical habitabiltty analyses, repairing the CRE boundary, or a combination of these actions. Depending upon the nature of the problem and the corrective action,*a full scope 1nleakage test may not be necessary to establish that the CRE boundary has been restored to OPERABLE status.
( contfnuedJ PBAPS UNIT 2                          B 3.7-20-a                  Rev1sion No. 116
 
                                                                                          ,MCREV System I
B 3. 7.4 BASES (cont1nued)
REFERENCES        L    Uf'."SAR, Section 7.19.
: 2. UFSAR, Section 10.13.
: 3. UF_SAR, Section 12.3.4 .
4, UFSAR, Sect1on 14.9.
: 5. NEDC-32988-A, Rev1s1on 2, Techn1cal Justif1cation to Support R1sk-Informed Mod1fication to Selected Required End States for BWR Plants, December 2002.
: 6. Regu1atory Gu1de 1.196, "Control Room Habitability at Light~Water Nuclear Power Reactors", May 2003.
: 7. NEI 99-03, "Control Room Habftab1lity Assessment", June 2001.
: 8. TSTF-448, Rev. 3, "Control Room Habitabil1ty" dated 8/8/06 and "Corrected Pages for TSTF-488, Rev. 3, Control Room Hab1tabil1ty", dated 12/29/06.
I
: 9. Letter from Erk J. Leeds (NRC) to James W. Davis (NE1) dated January 30, 2004, "NEI Draft Wh1te Paper, Use of Gener1c Letter 91-18 process and Alternative Source
            - - - - - - ~ - --- --- i"-erms-i11---the- C-ont-ext-of-CtfflJFol--RQoml,ab1tab7 lTty-:-"~ ------~ -
: 10. NR'C Regulatory Guide 1.78, Evaluating the l--fabitab1lity of a Nuclear Power Plant Control Room during a Postulated Hazardous Chem1tal release, Rev. 0.
: 11. NRC Regulatory Guide 1.95, Protection of Nuclear Power Plant Control Room Operators Aga1nst an Acc1dental Chlorine Release, Re~. 0.
: 12. Calcu1at1on PM-1085, ~Peach Bottom Atomic Power Station Contro1 Room Hab1ta0tl ity Analysis for the Off-site Chemicals."                                                          1-
: 13. Calculat1on PM-1175, "Control Room Habitabil1.ty for Chemlcals Stored Onsite."
I          PBAPS UN IT 2                            B 3.7-21                        Rev1S1on No. 121
 
Main Condenser Offg.as B 3.7.5
'          8 3. 7 PLANT SYSTEMS B 3.7.5 Main Condenser Offgas BASES BACKGROUND        During unit operation, steam. from the low pressure turbine is exhausted directly into the condenser. Air and noncondensible gases are collected in the condenser, then exhaus,ted through the steam jet air ejectors (SJAEs) to the.
Main Condenser .Offgas System. The. offgas from the main condenser nonaally tncludes radioactive gases.
The Main Condenser Offgas System has bee,n incorporated into the unit design io reduce the gaseous radwaste emission.
This system uses a catalytic recombiner to recombine radiolytically dissociated hydrogen and oxygen.. The gaseous mixture is cooled and water vapor re1110ved by the offgas recombiner condenser; the remaining water and cor'ldensibles are stripped out by the cooler condenser and 110isture separator. The remaining gaseous mixture (i.e., the offgas recombiner effluent) is then processed by a charcoal adsorber bed prior to release,
  ~        APPLICABLE        The main condenser offgas gross gamna activity rate is an
~~--S=A=F=ffi~ANALY.S.ES___j_rr_U_i_aLc.o.ndition_of____the.....Hai n.J:ondense~Offgas System---~
failure event, discl.lssed in the UFSAR, Section 9.4.5
(.Ref. 1). The analysis assumes a gross failure in the Main Condenser Offgas System that results in the rupture of the Main Condenser Offgas System pressure boundary. The gross gamma activity rate is controlled to ensure that, during the ev.ent, the calculated offsite doses will be well within the limits of 10 CFR 100 (Ref. 2) or the NRC staff approved licensing basis.
The main condenser offgas limits satisfy Criterion 2 of the NRC Policy statement.
LCD              To ensure_ compliance with the assWRptions of the Main Condenser Offgas System failure event (Ref. 1), the fission product release rate should be consistent with a noble gas release to the reactor coolant of 100 &#xb5;ti/MWt-second after decay of 30 minutes. The LCO 1s established consistent
{cont1nuedl PBAPS UNIT 2                              B 3.7-22                          Revision No. o
 
Main Condenser 0ffgas B' 3.7.5 I BASES LCO                        with this requirement (3293 MWt x 100 &#xb5;Ci/MWt-second =
(continued)              32.0,0'00, &#xb5;Ci/second) and is based on the original 1icensed rated therma1 power.
APP LI CAB I UTY            The LCO is applicable when steam is being ekhau~ted to the main condenser and the resu1ting rtoncondensible:s are being processed via the Main Condenser Offgas System. This occurs du~ing MODE 1, and during MODES 2 and 3 with any main steam litie not isolated and the SJAE in operation. In MODES 4 and 5, steam is not being exhausted to the main condenser and the requirernents are not applicable.
ACTIONS                    A...l If the offgas radioactivity rate limit is exceeded, 72 hour~
is allowed to restore the gross gamma activity rate to within the limit. The 72 hour Completion Time i5 reasonable, based on engineering judgment, the time required I
to complete the Required Action, the 1arge margins associated with permisstble dose and exposure limits, and the low probability of a Main Condenser Offgas System rupture.
B.1. B,2,  and B.3 If the gross gamma activity rate is not restored to within the limits in the associated Completion Time, all main steam lines or the SJAE must be isolated. This isolates t~e Main Condenser Offgas System from the source of the radioactive steam. The main steam lines are considered isolate*d if at least one main steam isolation valve in each main steam line is closed, and at least one main steam line dra,in valve in each drain lfne inboard of the main steam isolation valves is closed. The 12 hour Completion Time is reasonable, based on operating experience, to perform the actions from full power conditions in an orderly manner and wtthout challenging unit systems.
An alternative to Required Actions B.1 and B.2 is to place the unit in a MODE in which the overall p~ant risk is mi ni mi z ed . To a c hi eve th i s s ta t us , t he unit rn us t be pl a ce d in at least MODE 3 within 12 hours. Remaining in the Applicability of the LC0 is acceptable because the plant risk I                  ,,.~:.,,.,
                      ~~;~~
PBAPS UNIT 2                                    B 3.7-23                            Revision No. 66
 
Main ~ondenser Offgas B 3.7.5 I  BASES ACTIONS          8,1. B.2. and            B.3 (continued) in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status wil1 he short. However, voluntary entry into M_ODE 4 may be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on operating experiehce, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
SURVEILLANCE      SR 3.7.5.1
  ,REQUIREMENTS This SR requires an isotopic analysis of an Offgas sample to ensure that the required limits are satisfied. The noble gases to b,e sampled are Xe-133, Xe-135, xe-138, Kr-85m, Kr-87. and Kr-88. If the measured rate of radioactivity increase~ significantly (by~ ~0% after corfecting for expected increases due to changes tn THERMAL POWER), an isotopic analysis is also performed within 4 hours after the increase is noted, to ensure that the increase is not indicative of a sustained increase ih the radioactivity rate. The Surveillance Frequency is controlled under the
              -----5-i:i rve 'i ~+a nee---F-r eqtie rrc-y---on t-rot-----P r 6 &sect;-r-a m-:- * - - - - - - ~ -      1-This SR is modified by a Note indicating that the SR is not required to be performed until 31 days after any main steam line is not isolated and the SJAE is in operation. Only in this condition can radioactive fission gases be in the Main Condenser Offgas System at sig~ificant rates.
REFERENCES        1. UFSAR, Section 9.4.5.
: 2. 10 CFR 100.
: 3.      NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Re.quired End States for BWR Plants, December 2002.
PBAPS UN IT 2                                B 3.7-24                                          Revision No. 86
 
Main Turbine Bypass System I
B 3.7.6 B 3,7  Plant SYSTEMS B 3.7,6 Main Turbine Bypass System BASES BACKGROUND        The Main Turbine Bypass System is designed to control steam pressure when reactor steam generation exceeds turbine requirements during unit startup, sudden load reduction, and cooldown. It allows excess steam flow from the reactor to the condenser without goi.ng through the turbine. The. bypass capacity of the system is 21.96% of the Nuclear Steam Supply System rated steam flow. Sudden load reductions within the capacity of the steam bypass can be accommodated without safety relief valves opening or a reactor scram. The Main Turbine Bypass System consists of nine modulating type hydraulically actuated bypass valves mounted on a valve manifo1d. Tf:ie manifold is connected with two steam lines to the four main steam lines upstream of the turbine stop va1ves. The bypass valves are controlled by the bypass cor:itrol function of the Pressure Regula tor and Turbine Generator Control System, as discussed in the UFSAR, Section I
7.11.3 (Ref. 1). The bypass valves are normally closed.
However, if the total steam flow si gna1 exceeds the t1t1rbine control valve flow signal of the Pressure Regulator and Turbine Generator Control System, the bypass control function wiJJ o_u.tput a by.pass-fJoW-signal-to--the---0ypass--~-----
valves. The bypass* valves will then open sequ*entially to bypass the excess flow thro~gh connecting piping and a pressure reducing orifice to the condenser.
APPLICABLE        The Main Turbine Bypass System is expected to function SAFETY ANALYSES  during the electrical load rejection transi,ent, the te1:1rbine trip transient, and the feedwater controller failure maximum demand transient, as described in the UFSAR, Section 14.5.1.1 (Ref. 2), Section 14.5.1.2.1 (Ref. 3). and Section 14. 5. 2.2 (Ref. 4). However, the. feedwater    -
controller maximum demand transient is the limiting litensing basis transient which defines the MCPR operating limit if the Main Turbine Bypass System is inoperable.
Opening the bypass valves during the *pressurization events mitigates the increase in reactor vessel pressure, which affects the MCPR during the event.
The Main Turbine Bypass System satisfies Criterion 3 of the NRC Policy Statement.
(continued)
PBAPS UNIT 2                          .B 3.7-25                  Revision No. 143
 
Main Torbine Bypass System B 3.7.6 I      BASES  (continued)
The Main Turbine Bypass System is required to be OPERABLE to limit peak pressur~ in the main steam lines and maintain reactor pressure within acceptable limits d~rtng events that cause rapid pressurization, so that the Safety Limit MCPR i.s not exceeded. With the Main Turbine Bypass System inoperable, modifi,cations to the APLHGR operating limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), the MCPR operating limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), and the LHGR operating limits (LCO 3 .2. 3, "LINEAR HEAT GENERATION RATE (LHGR) ") may be -
applied to allow this LCO to be met. The operating limits for the inoperable Main Turbine Bypass System are specified 1n the COLR. An OPERABLE Main Turbine Bypass System requires the minimum number of bypass valves, speci'fied in the COLR, to open in response to increasing main .steam line pressure. This respons,e is within the assumptions of the applicable analyses (Refs. 2, 3, and 4).
APPLICABILITY      The Main Turbine Bypass System is required to be OPERABLE at
                            ; ;-: 22.6% RTP- to ensure that the f1:1el cladding integrity Safety Limit and the cladding 1% plastic strain limit are not violated during the applicable safety analyses transients.
As discussed in the Bases for LCO 3~2.3, '"LINEAR HEAT GENERATION RATE (LHGR)," and LCO 3. 2. 2, sufficient margin to
____ --* -~--- _- - -----these-~mi-t-s-ex-fsts-a-t-<-22.6%'....R=rP-;-- -"fherefore,-thes-e----- -- ~ - -----cj'-
requi rements are only necessary when operating at'or above this power level.
AffiONS            A.,_1 If the Main Turbine Bypass System is inoperable (one or more required bypass valves as specified in the COLR inoperable),
or the required thermal operating limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are not applied, the assumptions of the design basis transient analyses may not be met. Under such circumstances, prompt action should be taken to restore the Main Turbine Bypass System to OPERABLE status or adjust the thermal operati,ng limits accordingly. The 2 hour Completion Time is reasonable, based on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass System.
(continued)
PBAPS UNIT 2                              B 3.7-26                      Revision No. 143
 
Main Turbine Bypass System a 3.7.6 I ~BA_s_E_s~~---~-----------------------
ACTIONS        Ll
{continued)
If the ~ain Turbine Bypass System cannot be restored to OPERABLE status or the required thermal operating limits for an inoperable Main Turbi,ne Bypass System are not applied, TIIERMAL POWER must be reduced to< 22.6% RTP. As d1sc1:1ssed in the Applicabi1ity section, operation at< 22.6% RTP results in sufficient margin to the required limits, and the Main Turbine By,pass System is not required to protett fuel integrity durir:ig the ~pplicable safety analyses transients.
The 4 hour Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner without chal'lenging unit systems.
SURVEILLANCE    SR 3.7.6,1 REQUIREMENTS Cycling each main turbine bypass valve through one complete cycle of full travel demonstrates that the valves ar,e mechanically OPERABLE and wil1 function wlien required .. Th_e Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                - SR, 3,.J. W-~ -- -~
The Main Turbine Bypass System is required to actuate automatically to perform its design function. This SR demonstrates that. with the required system initiation.
signals, the valves will actuate to their required position.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
(continued)
PBAPS UNIT 2                      B 3.7-27                    Revision No. 143
 
Main Turbine Bypass System B .a. 7 .6 I BASES SURVEILLANCE  SR 3.7.6.3 REQUIREMENTS (continued) This SR ensures tlaat the TURBINE BYPASS SYSTEM RESPONSE TIME is in compliance with the assumptions of the appropriate safety analyses. The response time limits are specified in COLR. The Surveillance Frequency is controlled under the Surv_eillance Frequency Control Program.
REFERENCES    1. UFSAR, Section 7.11.3.
: 2. UFSAR, Section 14. 5 .1.1.
: 3. UFSAR, Section 14. 5.1. 2.1.
: 4. UFSAR, Section 14.5.2.2.
: 5. Deleted
: 6. NEOC-3.~873P, "Safety Analysis Report for Peach Bottom Atomic Power Station, Units 2 and 3, The~al Power Optimization," Revision O.
PBAPS UNIT 2                    B 3.7-28                    Revision No. 143
 
Spent Fuel Storage Pool Water Level*
B 3.7.7 I  B 3.7 PL.ANl SYSTEMS B 3.7.7  Spent Fuel Storage Pool Water Level BASES Th-e minimum water 1 evel in the spent fuel storage pool meets the assumptions of iodine decontamination factors following a fuel handling accident.
A general description of the spent fuel storage pool design is found in the UFSAR, SectiQn 10.3 (Ref. 1). The assumptions of the fuel handling accidertt are found in the UFSAR, Section 14.6.4 (Ref. 2).
APPLICABLE        The water level above the irradiated fuel assemblies is an SAFETY ANALYSES    implicit assumption of the fuel handling accident. A fuel handling accident is evaluated to ensure that the                _
radiological consequences are well below the guidelines set forth in 10 CFR 50.67 (.Ref. 3) as modified by Regulatory Guide 1.183, Table 6. A fuel handling accident could I.
release a f'raction of the fissioh product inventory by breachi~g the fLlel rod cladding as discussed in Reference 2 .
The fuel handling accident is evaluated for the dropping of
                -~-aA-=i--F-Fae-=l-at-ed-fue-l-assemel-y-o---0At-o4--he-reae:tQF-OOFe.---T,l=le----
consequences of a fuel handling accident over th~ spent fuel storage pool are less severe than those of the fuel handling accident over the reactor core. The water level in the spent fuel storage pool provides for absorption of water soluble fission product gases before being released to the secondary containment atmosphere. Noble gases are not retained in the water and particulates are retained in the water (RG 1 .183, Appendix B, Item 3).
The spent fuel storage pool water level satisfies Criteria 2 and 3 of the NRC Policy Statement ..
LCO                The specified water level (232 ft 3 inches plant e1evation, which is equivalent to 22 ft over the top of irradiated fuel assemblies seated in the spent fuel storage pool racks) preserves the assumptions of the fuel handling accident analysis (Ref. 2). As such, it is the mi~imum required for fuel movement w1 thin the spent fuel storage pool .
~-
(continued)
PBAPS UNIT 2                            B 3.7-29                          Ravi sion No. 75
 
Speht Fuel Storage Pool Water Level B 3.7.7 BASES      (contihued)
'            APPLICABILITY          This LCO applies during movement of fuel assemblies in the spent fuel storage poo1 since the potential for a release of fission products exists.
ACTIONS                A...l.
Required Action A.1 is modified by a Note indicating that LCO 3.0.3,dos not apply. If moving fuel assemblies while in MODE 1, 2, or 3, th.e fuel movement is independent of reactor aperations. Therefore, inability to suspend movement of fuel assemblies is not a sufficient reason to require a,*reactor shutdowh.
When t he i nit i a l con d it 1on s fo r a n a.cc i d*e nt ca nnot be met
* action must be taken to preclude the accident from occurring. If the spent fuel storage pool level is less than required, the movement of fuel assemblies in the spent fuel storage pool is suspended immediate1y. Suspension of this activity ~hall not preclude completion of movement of a f ue l a s s e m.b l y t o a. s a fe po s1 t i on . Th i s effect i ve l y precludes a spent fuel ~andling accident from occurring.
SURVEILLANCE          SR, 3,7,7,1
~~-  ----------R-~ W--RB-1 E-NYS Thi s SR v.e r i f i es th.at s uff i c i en t water i s av ai l ab l e i n th*e event of a fuel handling accident. The water level in the spent fuel storage pool must be chec::ked periodically. The Surveillance Frequency is controlled under the Surveillance Freque,ncy Control Program.
REFE-RENCES            1. UFSAR, Section 10.3.
: 2. UFSAR, Section 14.6.4.
: 3. 10 CFR 50.67.
,I/
PBAPS UNIT .2                                    B 3.7-30                            Rev i s i. on No . 86
 
AC Sources-Operating B 3.8.1 B 3.8  ELECTRICAL POWER SYSTEMS
' B 3.8.1 BA~ES AC Sources-Operating BACKGROUND        The unit AC sources for the Class lE AC Electrical Power Distribution System consist of the offsite power sources,*
and the onsite standby power sources (diesel generators (DGs)). As required by UFSAR Sections 1.5 and 8.4.2 (Ref. 1}, the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.
The Class lE AC distribution system is divided into redundont load groups, so loss of any one group does not prevent the minimum safety functions from being performed.
Each load group has connections to two qualified circuits that connect the unit to multiple offsite power suppltes and
: a. single DG.
I                    The two qualified circuits between th Offsite transmission network and the onsite Class lE AC Electrical Power Distri*bution System are supported by multiple., independent offsite power sources. One of these qualified circuits can
              -~-,b e--GG n Re &t-e d-t0-e4-t-A-e-f'--G--f-t--w 0-0 f..f--s---i--- t-&--5 0 u rt-&S -t-h ~ - - - ~ -
pref er red offs ite source is the 230 kV Nottingham- Cooper                                    l 1 i. ne W, hi c h s upp 1 i e s t .h e pl a nt th r OH g h, t he 230/13 . 8 kV startup and emergency auxiliary transformer no. 2; the alternate offsite source is the auto-transformer
{500/230 kV) at North Substation which feeds a 230/13.B kV regulating transformer (startup and emergency auxiliary transformer no. 3), the 3SU regulating transformer switchgear, and the 2SUA switchgear. The aligned source is further stepped down via the 2SU startup transformer switchge~r through the 13.2/4,16 kV emergency auxiliary transformer no. 2. The other_qualified circuit can be connected to either of two 0ffsite sources: the preferred offsite source is the 230 kV Peach Bottom-Newlinville line which supplies a 230/13.8 kV transformer (startup transformer na. 343); the alternate .offsite source is the auto-transformer (500/230 kV) at North Substation which feeds a 230/13.8 kV regulating transformer (startup and emergency auxi.liary transformer no. 3) and the 3SU regulating transformer switchgear. The aligned source is further stepped down via the 343SU transformer switchge~r I PBAPS UNIT 2                                                                                      Revision No. 82
 
AC Sources-Operating B 3 .. 8.I BASES BACKGROUND    through the 13.2/4.16 kV emergency auxiliary transformer (continued) no. 3. In addition, the alternate source can only be used to meet the requ1rements of one offsite circuit. A detaiJed description of the offs1te power network and circuits tb the onsfte Class lE ESF buses is found in the UFSAR, Sections 8.3 and 8.4 (Ref. 2).
A qualified offsite circuit consists of all breakers, transformets, switches, interrupting devices, c.abling, and controls required to transmit power from the offsite transmission network to the onsite Class lE emergency bus or buses. The determination of the operabflity of a qualified source of offsite power is dependent upon grid and plant factors that, when taken together, describe the design basis calculation requirements for voltage regulation. The combination of these factors ensures that the offsite source(s), which provide power to the pla_nt emergency buse.s, will be fully capable of supporting the equipment required. to achieve and maintain safe shutdown during postu1ated ac~idents and transients.
The plant factors consist of the status of the Startup Transformers' (2SU, 343SU, 3SU) load tap changers (LTC's), the status of the Safeguard Transformers (2EA and 3EA) and the alignment of the emergency buses on the Safeguard Buses ~OOA019
- - - - - ~ _________and_QOAQ.20). .--Fd-r-a n .-0--ffs.-lt-e--s eu11ee-t-0 -b e-----co ns-i -cl ered--o p*e-r ab*1-e,~-----------
i ts respective LTC's must be in service and in automatic.                                        I The grid factors consist of actual grid voltage levels (real time) and the post trip .contingency voltage drop percentage value.
The minimum offsite source voltage levels are established by the voltage regulation calculation. The transmission system operator (TSO) will notify Peach Bottom when an agreed upon limit is approached.
The post trip contingency percentage vol tag.e drop is a calculated value determined by the TSO that would occur as a result of the tripping of one Peach Bottom generator. The TSO will notify Peach Bottom when an agreed upon limit is exceeded.
The voltage regulation calculation establishes the acceptable percentage voltage drop based upon plant configuration.
PBAPS UN IT 2                                                                        Revision No. 90
 
fiif AC Sources-Operating B 3.8.1 BASES BACKGROUND        Due to the 3SU source being derived from the tertiary of the
( cont tnued)  #1 Auto Transformer, its o~erabi1ity is influenced by both the 500 kV and 230 kV systems. The 2SU and 343SU sources operability is influenced only by the 230 kV system.
Peach Bottom unit post trip contingency voltage drop percentage cal cul ~ti ons are performed by the ~OM Energy Mana.gement System (EMS). The PJM EMS consists of a primary and backup system.
Peach Bottom will be notified if the real time contingency analysis capability of PJM is lost. Upon receipt of this notification, Peach Bottom is to request PJM to provide an assessment of the current condition of the grid based on the tools that PJM has available. The determination of the operab{lity of the offsite sources would consider the assessment provided by PJM and whether the current condition of the grid is bounded .by the grid studies previously performed for Peach Bottom,.
* Variations to any of these factors is permissible, usually at the sacrific~ of another factor, based on plant conditions.
Specifics regarding these variations are controlled by plant I                          procedures or by condition specific design calculations.
A description of the Unit 3 offsite power sources 1s provided in the Bases for Un_:LL3 LC0_3....1L_l, __'.'__ACSm.lr.-ce-S~--* ---*-
- - "~--------~-{);J;el'atTng.1'--Tfieo.escrTpti on is identical with the exception that the two offsite circuits provide power to the Unit 3 4 kV emergency buses (1.e., each Unit 2 offsite circuit is common to its respective Unit 3 offsite circuit except for the 4 kV emergency bus feeder breakers).
PBAPS UNIT 2                          B 3.8-2a                        Revision No. 90
 
AC Sources-Operating B 3.8.1 I  6ASES BACKGROUN,D  The onsite standby power source for the four 4 kV emergency (continued) 13 us es i n e a c h uni t cons i s t s o f f ou r DGs . The fo ur DGs prov, de ons He standby power for both Unit 2 and Unit 3.
Each DG provides standby powet to two 4 kV emergency buses-one associated with Ur:iit 2 and one associated with. Unit 3:**-"
A DG starts automatically on a loss of coolant accident**,* *
(LOCA) signal Ci .e., low reactor water levei signal or high drywell pressure signal) from either Unit 2 or Unit 3 or on an emerg,ency bus* degraded voHage or undervoltage signal.
After the DG has started, it automatically ties to its respective bus after o.ffs1te power is tripped as a consequence of emergency bus undervoltage or degraded voltage, independent of or coincident with. a LOCA signal .
The DGs also start and operate in the standby mode without tying to the emergency bus on a LOCA signal alone.
Following the trip of (,,ffsite power, al1 lo,ads are stripped from the emergency bus. When the DG is tied to the emergency bus, loads are then sequentially connected to its respective emerge,ncy b1:1s by individual timers associated with each auto-connected load fo716wing a permissive from a voltage relay monitoring each emergency bus.
In the event of a loss of both offsite power sot.:1rces, the ESF electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor s.hutcl91!'.JLQ.f_
  *----------1%Fn. unifs and ~o mftigate the consequences of a Design Basis Accident (OBA) such as a LOCA. Within 59 seconds
* after the initiating signal is received, all automatically connected loads ne.eded to recover the unit or maintain it in a safe condition are returned to service. The failure of any one DG does not impair 5afe shutdown because each DG serves an independent, redundant 4 kV emergency bus for each unit. The remaining DG.s and emergency buses have sufficient capability to mitigate the consequences of a OBA, support the shutdown of the other unit, and maintain both units tn a safe condition.
Ratings for the DGs satisfy the requ1rements of Regulatory Guide 1.9 (Ref. 12). Each of the four DGs have the following ratings:
: a. 26 OO kW -  con ti nuous ,
: b. 3000 kW- 2000      hours,
: c. 310 0  kW - 2 0 O hours ,
: d. 3 250 kW - 3 O mi nut es .
(continued)
PBAPS UNIT 2                            B 3.8-3                          Revis.ion No. 114
 
AC* Sources-Operating B 3.8.l BASES (continued)
APPLICABLE        The initial conditions of OBA and transient analyses in the SAFffi ANALYSES    UFSAR, Chapter 14 {Ref. 4), assume ESF systems are OPERABLE.
The AC e1ectrical power sources are designed to provide sufficient capacity,_ capability, redundancy, and reliabfl ity to ensure the avail ability of necessary power to ESF systems so that the fue1, Reactor Cool~nt System (RCS), and containment design li111ts are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution. Limits; Section 3.5, Emergency Core Cool i ng. Syst811S ( ECCS*) and Reactor Core Isolation Cool ing (RCIC) System; and Section 3 .6, 1
Containaent Systems.
The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the accident analyses and 1s based upon meeting the design basis of the unit. This includes 111aintaining the onsite or offsite AC sources OPERABLE during accident conditions in the event of:
: a. An assUlled loss of all offs1te power or all onsite AC power; and
: b. A worst case s i ng,l e failure.
AC sources satisfy Criterion 3 0f the. NRC Pol icy Statement.
                          /
LCO                Two qualified circuits between the offsite transmission network and the onsite Class IE Distribution System and four separate and independent DGs ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an abnormal operational transient or a postulated OBA. In addition, since some equipment required by Unit 2 is powered from Unit 3 sources (i.e., Standby Gas Treatment (SGT) System, emergency heat sink components, and Unit 3 125 voe battery chargers)~
qualified circu1t(s) between the offsite tranS111ission network and the Unit 3 onsi'te Class lE .AC alectrical power distribution subsyste11(s) needed to support this equipment must also be OPERABLE.
An OPERABLE qualified Unit 2 offsite circuit consists of the i ncom:i ng breaker and disconnect to the startuP:-.and emergency auxiliary transformer, the respective circuit path to the emergency auxiliary transfonaer, and the circuit path to at least three Unit 2 4 kV emergency buses including feeder Ccont,nyedl PBAPS UNIT 2                            B 3.8-4                        Revision No. O
 
AC Sources-Operating
                                                                              .B 3. B .1 I BASES LCO            breakers to the three !]nit 2 4 kV emergency buses.        If. at_
( continued) Least one o( the two circuits_ does not provide power - or 'is not capable of provid:Lng power to all four Unit 2 4 kV emergency buses, then the Unit 2 4 kV emergency buses that each cir~ult powers or is capable of power~ng cannot all be the same (i.e., two feeder breakers on one Unit 2 4 kV emergency bus cannot be inoperable).      If two feeder breakers are inoperable on the same 4kV bus, then Condition A (and Condition E if an inoperable DG exists) mtist: be entered for one offsite circuit being uroperable even if both offsite circuits otherwise provide power or are capable of providing power: 11:o the other thr~e 4kV buses. An OPERABLE qualified Unit 3 offsite circuit's requirements are the same as the Unit 2 circuit's requirements, except that the circuit path, including the feeder breakers, is to the Unit 3 4 kV
                  -emergency buses req1,ured to bE! OPERABLE by LCO 3. B. 7, hQistribution Systems-Operating.fl Each offsite circuit must be capable of maintaining rated fr.equency and voltage, and accept::ihg required loads during an accident, while connected to the emergency buses.
I                Each DG has two ventilation supply fans; a main supply fan and a supplemental supply fan.      The ~upplemental supply fan provides additional air cooling to the gener.ator area.
Whenever ou,tside air ternp~r;ature is g,reater tha'n or _g_qual____.,;;t.=o_ __
80&deg; F, each DG's ntain supply fan anct s1,1pplemental supply fan ate required to be OPERABLE for the associated DG to be OPERABLE. Whe,never, outside air temperature is less than 80&deg; F, the supplemental supply fan is hot required to be OPERABLE for the associated DG to be OPERAELE, howev~r, the main supply fan is required to be OPERABLE for the associated DG to be OP.ERABLE.
Each DG must be capable of startingr acceler~ting to rated speed and voltage, and connecting to its respective Unit 2
: 4. kV emergency bus on detection of bus undervoltag,e.        This sequence rrtust be c!Ccornplished within 10 :,ecol)ds. Each DG must alsQ be capable of ac~epting req;uired loads within the assumed loading sequence intervals, and must cont~nue to operate until off,si te power, ,can be restored to the emergency buses,    These capabilities ar:e required to be met from a vc1riety of initial conditions, such as DG in standby with the engine hot _and DG in standby with the engine at ambient condition. Additional DG capabilities must be demonstrated to m~et required Surveillan&#xa2;es, e.g., capability of the DG to rever~ to stpndby status on an ECCS signal while I                operating in pcl,.r:allel test mode. Proper seql:lencing of loads, including tripping of all loads, is a required function for DG OPERABILITY.
( continued)
PBAPS UNIT 2                        B 3'.8-5                      Revision No. 73
 
AC Sources-Operating B 3.8.1 I      BASES LCO          In addition, since some equi.pme.nt required by Unit 2 1s (continued)  powere? from U~it 3 sources, *the DG(~) capable of su~ply~ng the Unit 3 onsite Class lE AC electrical power distribution subsystem( s) needed _to support this equipment must be OPERABLE. The OPERABILITY requirements for these DGs are the same as described above, except that each required DG must be capabl.e of connecting to its respective Uni't 3 4 kV emergency bu~. (In addition, the Unit 3 ECCS initiation logic SRs are not applicable, as described in SR 3.8.1.21 Bases.)
The AC sources must be separate and independent (to the extent possible) of other AC sources. For the DGs, the separation and independence are complete. For the offsite AC sources, the separation and independence are to the extent prc1cti cal. A circuit may be* connected to more than one 4 kV emerge-ncy bus division, with automatic transfer capability tb the other circuit OPERABLE, and not violate separation criteria. A circuit that is not connected to at l~ast three 4 kV emergency buses is required to have OPER'ABLE automatic transfer interlock mechanisms such that it can provide power to at least three 4 kV emergency buses to support OPERABILITY of that circuit.
I      APPLICABILITY The AC sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure that:        *
--~--------~------.a~ ---Acee pt a.tl~-e-f-U e W e-&-1/2n-l +m-4-ts-a-n El-r-e a c-t-o-r--G00-3/4fl-t- ~ - - - -
pressure b9undary limits are not exceeded as a result of abnormal operational transients; and
: b. Adequate core cooling is provided and containm~nt OPERABILITY and other vital functions are maintained in the event ,of a postulated OBA.
The AC power requirements for MODES 4 and 5 are covered in LCO 3.8.2, "AC Sources-Shutdown."
ACTIONS      A N0te prohibits the application of LCD 3.0.4.b to an inoperable DG. There E. an increased r1sk associated with entering a MODE or other specified condition in the Applicabili~ywith an inope~able DG 1rnd the provisio~s.of LCD 3.0.4.b, which allow entry rnto a MODE or other specifred condition in the Applicability with the LCO not met after performance of a risk assessment addressfn,g inope.rabl e systems and components, should not be applied in this ci rcumstar1 ce.
1 A...1 To ensure a highly reliable powe.r source remains with one I                    offsite circuit inoperable, it is necessary to verify the availability of the remaining offsite circuits on a more frequent basis. Si nee the Required Action only specifies "perform," a failure of SR 3.8,1,1 acceptance criteria does PBAPS UN IT 2                      R  3.8-n                                      Ri:>11ic:inn '1?
 
AC Sources - Operating B 3.8.1 I      BASES ACTIONS            AJ. (conttnued) not result in a Required Action not met. However, if a second circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition D, for two offsite circuits inoperable, is ent~red.
                            &Z Required Action A.2, which only applies if one 4 kV emergency bus cannot be powered frORJ any offsite source, is intended to provide assurance that an event with a                  -
coincident single failure of the associated D6 does not result in a complete loss of safety function of critical systems. These feature_s (e.g .. , system, subsystem, division, component, or device) are designed to be powered frOIJI redundant safety related 4 kV 8111ergency buses. Reduhdant required features tailures consist of inoperable- features associated cwtth an emergency bus redundant to the emergency bus that has no offsite power.
The C0111p 1et ion Time for Required Action A. 2 i s, 1ntended to allow time for the operator to evaluate and repair any discovered inoperabilities. This COlllJ)letion. Time also allows an exception 'to the nonpal "ti110 zero" for beginning
- - ~ - - - ~ - -----the--,-a~-lowed-ou-t-age4--i me-''-eloclc.-1'----1-n----t-h-i-s--Reqtti-red----Actton--~
the C01PPletion Time only begins on discovery that both:
: a. A 4 kV emergency bus has no offsite power supplying its loads; and b.. A redundant required feature on another 4 kV. emergency bus is inoperable.
lf, at any time during the existence of this Condition (one offsite circuit inoperable) a required feature subsequently becomes inoperable, this Completion Time woulo begin to be tracked.
* Discovering no offsite power to one 4 kV emergency bus of the onsite Class IE Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with any other emergency bus that has offsite power, results in starting the COQlpletion Times for the Requireo Action. Twenty-four hours ls acceptable because it minimizes risk while allowing time for restoration before the unit i's subjected to transients associated with shutdown.
(continued)
PBAPS UNIT 2                            B 3~8-7                                Revision 5
 
AC Sources-Operating B 3.8.1 BASES
'  ACTIONS            LJ (continued)
The remaining OPERABLE offsite circuits and  Gs are adequate to supply electrical power to the onsite Class lE Distribution System. Thus, on a component basis, single failure protection may have been 1ost for the required feature's function; however., function is not lost. The 24 hour Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required fecJture. Additionally, the* 24 hour 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 OBA occurring during this period.
Ll The 4 kV emergency bus design and loading is sufficient to allow operation to continue in Condition A for a period not to exceed 7 days. With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a lo~s of offsite power is increased 1 with attendant potential for a challenge to the p*lant safety I                    systems. In this condit'ion, hOwever, the remaining OPERABLE offsite circuits and the- four DGs are adequate to supp1y electrical power to the onsite Class IE DistribUtion System.
              -----t-t'l e---r----d ay-G-om p*le-t-t-o n-T-'tme-tai<-e-s-imoacm-rrnere dun aan cy ,
capacity, and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a OBA occurring during this period.
PBAPS UNIT 2                                      B 3.8-8                      Revision Nao. 85
 
AC Sources -Operating B 3.8.1 BASES
' ACTIONS (continued)
Ll The 3 3 kV Con ow i ngo Ti e - Li ne , us i ng a s e pa rate 33 /13
* 8 kV transformer, can be used to supply the circuit normally I-supplied by startup and emergency auxiliary transformer no.
: 2. Whi1e not a qualifi.ed circuit, this alternate source is a direct tie to the Conowingo Hydro Station that provides a highly reliable source of power because: the line and transformers at twth ends of the line are dedicated to the support of PBAPS; the tie line is not subject to damage from adverse weather conditions; and, the tie line can be isolated from other parts of the grid when necessary to ensure its availability and stability to support PBAPS. The availabtlity of this highly reliabJe source of offsite pm,-er p-ermits an extension of the allowable out of service time for a DG to 14 days from the discovery of failure to meet LCO 3.8.1.a orb (per Required Action B.5). Therefore, when a DG is inoperable, it is necessary to verify the availability of the Conowingo Tie-Line immediately and once per 12 hours thereafter. The Completion Time of "Immediately" reflects. the fact that in order to ensure that I                  the full 14 day Completion Time of Required Action B.~ is available for completing preplanned maintenance of a DG~
prudent plant practice at PBAPS dictates that the avclilability of the Conowingo Tie-Line be verified Q_rior t_o__
  - - - ~ ----~-maki.ngcr-o:G--1 noperalSTefor prepl arined maintenance. The Cor1owingo Tie-Line is available and satisfies the requirements of Re qui red_ Action* B.1 if: 1) the Conow1 ngo line is supplying power to the 13.BkV SBO Switchgear D0A3O6;
: 2) all equipment required, per SE-11, to connect power from the Conowingo Tie-Line to the emergency 4kV buses and to isolate all non-SBO loads from the Conowingo Tie-line is available and accessible; and 3) communications with the Conowingo control room indicate that required equipment at Conowingo is available. If Required Action B.1 is not met or the I PBAPS UN I-T 2                        B 3.8-9                              Revision No. 85
 
AC Sources-Operating B 3.8.1 BASES
'          ACTIONS        U (continued}
status of the Conowingo Tie-Ltne changes -after Required Action B.I is initiaHy met, Condition C arust be inuediate.ly entered *
                          .Ll.
To ensure a highly reliable power source remains with one DG inoperable, it is necessary to verify the availability of the required offsite circuits on a more frequent basis.
Since the Required Action only specifies *perform," a, failure of SR 3.8.l.I acceptance cr1tetia does not* result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.l.I, it is inoperable. Upon offsite circuit inoperability, additional Conditions must then be entered.
Required Action B.3 is intended to provide assurance that a lgss of offsite power, during the ,period that a DG is inoperable, does not result in a complete loss of safety function of critical systees. These features are designed
~                        to be powered from redundant safety related 4 kV emergency buses. Redundant required features failures consist of
-----~-------noper-able-fea-tures--a-ssoctated-irltth-ant!IIM;frglffley-~ - - - - - --
redundant to the emergency bus that has an inoperable 06.
The Couipletion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Comp1et ion Ttme al so a11 ows for an exception to the normal "time zero" for beginning the allowed outage ti.me "clock."
In this Required Action the Completion Time only begins on discovery that both:
a.. An inoperable D6 exists; and
: b. A redundant required feature on another 4 kV eme.rgency bus is t~operable.
If, at any time during the exiStence of this Condition (one 0G inoperable), a required feature subsequently becomes inoperable; this Completion Time begins to    be tracked.
Discovering, one DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with t_he OPERABLE DGs results in (continued)
PBAPS UNIT 2                    B 3.8-10                            Revisjon 5
 
AC Sources-Operating B 3.8.1 I      BASES ACTIONS      Ll (continued) starting the Completio*n Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing tirn~ for restoration before subjecting the unit to tr,ansients associated with shutdown.
The remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class lE Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have beer:i lost; however*,. function has net been lost. The 4 hour Completion Time takes 1nt0 account the component OPERABILlTY of the redunda.nt counterpart to the inoperable required feature. Additionally, the 4 hour Completion Time takes into account the capacity and capability of the remaining AC sources, rea-so'11able time for repairs, and low probability of a OBA occurring during this period.
B.4.1 and B..4,2 1  '
    .              Required Action B.4.1 provides an allowance to avoid unnecessary testing of O~ERABLE DGs. If it can be determined that the cause of the inoperable DG does not ex 1st on t ne D'P Emrou-o Gs;--sR-----:rJ3~r:771oes-nm-have--r-otfe- ------
performed. If the cause of inoperability exists on other DG(s), they are declared inoperable upon discovery, and Condition For Hof LCO 3.8.1 is entered, as applicable.
Once the failure is repaired, and the common cause failure no longer exists, Required Action B.4.1 is satisfied. If the cause of the initial inoperable DG cannot .be co11firmed not to exist on the remaining OGs, performance of SR 3.8.1.2 suffices to provide assuraITce of continued OPERABILITY of those DGs.
In the event the inoperable DG is restored to OPERABLE status prior to completing either B.4.1 or B.4.2, the PBAPS Corrective Action Program will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer required_ under the 24 hour constraint imposed while in Condition B.
According to Generic Letter 84-15 (Ref.~), 24 hours is a reasonable time to confirm that the OPERABLE DGs are not affected by the same problem as the inoperable DG.
I-PBAPS UN IT 2                    B 3.8-11                            Revision 60
 
AC Sources - Operating B 3.8.1 I    BASES ACTIONS (continued)
The a*vailability of the Conowingo Tie-Line provides a_n addittonal source which permi.ts operation to continue in Cond.ition B for a periO<i' that should not exceed 14 days frORI discovery of the fa i 1ure to meet LCO 3. 8. 1. a or b. In Condition B, the remaining OPERABLE DGs'and the normal o.ffsite circ~its are adequate to supply electrical po~e.r to the onsite Class lE. Distribution Syst~.. The Compl,etion Time of Required Action B.5 takes into accpunt the enhanced reliability and avail ability of offsite sources due to the Conowingo Tie-Line.,* the redundancy, capacity, and capability of the other rema*ir1ing AC sources, reasonable time for _
repairs of the affected DG, and low probability of a DBA occurri.ng during this peri od.
1 The Comp'letion Time for Required Action B..5 also estabHsh.es a limit on the .maximum time allowed for any combination of requfred AC power sources to be inoperable during any single contiguous occurrence of fail ing to meet LCO 3. 8 .1. a or b.
If Condition B is entered while,, for instance, an offsite I.-
circuit fs inoperable and that circuit is subsequently res to.red OPERABLE, the LCO may al ready have been not met for up to 7 days. This situation could lead to a total of 14 days, since i.nitial fai*lt:1re of LCO 3~8.1.a orb, to restore
-~--~-~--~~~he_OG. At tlus..iime .-an offs itELC-ir.-e11lLcould_ agaJn_hecome___ _
inoperable, the DG restored OPERABLE, and an additional 7 days. (fop a. total of 21 days) allowed prior to, complete restoration of the LCO. ,Toe 14 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet LCO 3.8 .. 1.a orb. This limit is considered reasonable for situations in which.
Conditions A and Bare entered concurrently. The 14 day Completion Time would also limit the maximum time a DG is.
inoperable if the status of the Conowingo Tie-Line changes from being c1vailable to being not av_ailable (thiS is diScussed in .Required Action    c. 1 Bases discussion)".
As in Required Action .B.3, the Completion Time allows for an exception to the nonnal *time zeron for beginning the allowed outage time "clock,." This except ton results in
* establishing the "time zero" a~ the time that th*e LCO was initially not met, instead of the time that Condition B was entered.
Cc;:ontinyed}
PBAPS UNIT -2                    B 3.8-12                        Revision No. 1
 
AC Sources-Operating B 3 .8.. 1
' _BA_s_Es_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __
ACTIONS          M    .(continued)
The extended Comp1etion Time for restoration of an inoperable DG afforded by the availability of the Conowi ngo Tie-Ltne :is intended to allow completion of a diesel generator overhaul; however, subject to the diesel generator reliability program, INPO performance criteria, and good operating practices~ using the extended Completion Ti11e is permitted for other reasons. Activities or conditions that increase the probability of a loss of offsite power (1.e.,
switchyard maintenance or severe weather) should be considered when scheduling a diesel gene~ator outage. In addition, the effect of other inoperable p1, ant equipment should be considered when; scheduling a diesel generator
* outage.
Ll If the availability of the Conowingo Tie-Line is not verified within the Completion Time of Required Action 8.1, or if the status of the Conowingo Tie-Line changes after Required Action B.l is initially met, the DG 111ust be restored to OPERABLE status within 7 days. The 7 day Completion Ti111e begins upon entry into Condition C (i.e.,
upon discovery of failure to meet Required Action 8.1)~
However, the total time to restore an inoperable DG cannot exceed 14 days (per the CQIDPleti.on Time of Requ.ir-ed Action 8.5).                                                        .
The 4 kV emergency bus design and loading is sufficient to allow operation to continue in Condition B for a pe.riod that should riot exceed 7 days, if the Conowingo Tie-Line is not available (refer to Required Action B.I Bases discussion).
In Condition t, the remainin,g OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class lE Distribution System. The. 7 day Completion lime takes into account the redundancy, capacity, and capabiltty of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurri.ng during th 1s period.
{continued}
PBAPS UNIT 2                          B 3.8-13                    Revision No. O
 
AC Sources-Operating
                                                                      . B 3.8.1 BASES ACTIONS        D,l and P,2
{continued)
Required Action 0.1 addresses actions to be taken in the event of i noperabil 1ty of redundant required features concurrent With inoperabHity of two or 1110re offsite circuits. Required Action D.l reduces the vulnerability to a Joss of function. The Completion Time for taking these actions is reduced to 12 hours from that allowed with one 4 kV emergency bus without offs1te power (Required Action A.2). The rationale for the reduction to 12 hours is that Regulatory Guide 1.93 ('Ref. 6) allows a Completion Time of 24 hours for two .offsite circuits inoperable, based upon the assumpt.ion tha.t two complete .safety divisions are OPERABLE. (While this Action allows more than two circuits to be inoperab1e, Regulatory Gui de L93 assumed two *c1 rcui ts were all that were required by the LCO, and a loss of those two circuits resulted in a 1oss of all offsite power to the Class 1&#xa3; AC Electrical Power Distribution System. Thus, with the Peach Bottom At01Uic Power Station design, a loss of more than two offsite circuits results in the same conditions assumed i.n Regulatory Guide 1.93.) When a concurrent redundant required feature failure exists, this assUJDption is not the case, and a shorter Completion Time of 12 hours is appropriate. These features are designed with redundant safety related 4 kV emergency buses. Redundant required features fai]~ons_lsi_of_any_of_these_ieatur..e~S--
that a,re inoperable because any inoperabil ity is on *an emergency bus redundant to an emergehcy bus with inoperable offsite circuits.
* The Completion Time for Required Action D.l is i.ntended to allow the operator time to evaluate and repair any discovered inoperabi11t1es. This Completion Time also allows for an exception to the normal 11 time zeron for beginning the allowed. outage time "clock. 11 In this Required Action, the Completion Time only begins on discovery that
              .both:
: a. Two or more offsfte circuits are inoperable; and
: b. A required. feature is inoperable.
(contjnged}
PBAPS UNIT 2                      B 3.8-14                      Revision No. O
 
AC  Sources-Operating B 3.8.1 I _eA_s_Es--- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
ACTIONS            D.l and D.2 {continued) lf, at any time during the existence of this Condition {two or more offsite circuits inoperable i.e., any combination of Unit 2 and Unit 3 offsite circuits inoperable), a required feature subsequently becomes inoperable, this Completion Time begins to be tracked.
According to Regulatory Guide I. 93 (Ref. 6&deg;), operation may continue in Condftion D for a peri1od that should not exceed 24 hours. This level of degradation 1119ans that the offsite electrical power system may not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, the ons1te AC sources have not been degraded. This level of degradation generall'y corresponds to a total loss of the ianediately accessible offsite power sources.
Because of the normally high avai1ability of the offsite
                      .sources, this level of degradation may appear to be mre severe than other combinations of two AC sources inoperable that involve one or aore DGs inoperable. However, two factors tend to decrease the severity of this degradation level:                                            *
: a. The conf i gurat 1on of. tha__ndundant-AC--elecmca-l-power-~~-
syste111 that remains avaflable is not susceptible to a single bus or .switching failure; and
: b. The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unava 11 able ons i te AC source.
With two or more of the offsite circuits inoperable.,
sufficient onsite AC sources are avail able to maintain the unit in a .safe shutdown condition in the event of a OBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case.single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour Completion Time provides a period of time to effect restoration of all but one of the offsite circu.its tomnensurate with the importance of maintaining an AC electrical power system capable. of meeting its design criteria.
{continued)
PBAPS UNIT 2                                                          Revision No. O
 
AC Sources-Operating B 3,8.1 I BASES ACTIONS      D.l and P-2    (continued}
According to Regulatory Guide 1.93 (ReL 6), with the available offsite AC sources two less than required by the LC0, operation may continue for 24 hours. If all offsite sources are restored within 24 hours, unrestricted operation may continue.. If all but one offsite source is restored within 24 hours, power operation continues in accordance with Condition A.
E.I and E.2 Pursuant to LCO 3.0.6, the Distribution Systems-Operating ACTIONS wo1.1l d not be entered even 1f a11 AC sources to it .
were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition E are modified by a Note to indicate that *when Condition Eis entered with no AC source to any 4 kV emergency bus, ACTIONS for LCO 3.8.7, "Distribution Systems-Operating,* must be immediately entered. This allows Condition[ to provide requirements for the loss of the offstte circuit and one 06 without regal"d to whether a 4 kV emergency bus is de-energized.
LC0 3.8.7 provides the appropriate restrictions for a de-energized 4 kV emergency bus.
                                                  ----~-~----~~--
According to Regulatory Guide 1..93 (Ref. 6}, operation may continue in Condition E for a period that should not exceed 12 hours. In Condition E, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power systea. Since power system redundancy is provided by two diverse sources of power, however, the reliability of the power systems tn this Condition may appear higher than that in Condition D (loss of two or more offsite circuits). This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probabiHty of a DBA occurring during this period.
(continued}
PBAPS UNIT 2                    B 3.8'-16                    Revi s*i on No. O
 
AC S-0 ur ce s - Ope r at 1ng B 3.8.1 BASES ACTIONS        .L.1 (cont1nued)
With two or tnore DGs inope.rable, with c1_n assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions.
Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled sh utdown. (The immediat,e 1
shutdown could cause grid instability, which could result in a total loss of AC power.) Since any inadvertent unit generator tr1p cciuld also result in a total loss of offsite AC power, however. the time allowed for continued operation is severely restricted. The intent here fs to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.
According to Regulatory Guide. 1.93 (Ref. 6), with two or mo re DGs i no,p-e r a bl e , ope r a t i on may co nt i nue for a pe r i od that should not exceBd 2 hours. (Regulatory Guide 1.93 I                          assumed the unit has two DGs. Thus, a loss of both DGs results in a total loss of onsite power. Therefore, a loss of more than two DGs, in the Peach Bottom At0mic Power Station destgn., ~esults in degradation no worse than that
- - ~ ~ - ~ ~ ---"---------a~llll'IReg[J1 atory Gui de I. 9r.7--
Ll If the inoperabl~ AC electrical power source(s) cannot be restored to OPERABLE status within the associated Completion Time (Required Action and associated Completion Time of Condition A, C, D, E, or F not met; or Required Action B.2, B.3, B.4.1. B.4.2, or B.5 and associated Completion Time not met)j the unit must be brought to a MOD&#xa3; in which the overall plant risk is minimized. To achieve this status, the unit
                            .must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO 1s acceptable because the plant risk in MODE 3 is similar to or lower than the risk iD MODE 4 (Ref, 11) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 m~y be made as it is also an acceptable low-risk state. The allowed Completion Time is reasonable, based on op,erating experience, to reach the required pl ant conditi.ons from full power conditions in an orderly manner and without cha1lenging plant systems.
PBAPS UN IT 2                            B 3.8-17                              Revision No. 66
 
AC Sources -Opera ting B 3.8.1 I BASES ACTIONS          H.1 (continued)
Condition H corresponds *to a level of degradation in which redundancy in the AC electrical power supplies has been lost. At this sever~ly degraded level, any further losses in the AC electrical -power system may cause a loss of function. ThereforeJ no additional time is justified for continued operation.      The unit 1.-s required by LCO 3.0.3 to commence a controlled shutdown.
SURVEILLANCE    The AC sources are designed to permit inspection and REQU!REMENTS    testing of all important areas and features, especially those that have a standby function, in accordance with UFSAR, Section 1. 5 .1 (Ref. 7).      Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulatec:;l: accident conditions). The SR.s for demonstrating the OPERABILITY of th~ DGs are consistent w~th the recommendations of Regulatory Guide 1.9 (Ref. 3),
* Regulatory Guide 1.108 (Ref. 8), and Regulatory Guide 1.137 (Ref. 9~.
I                  M  Noted at the beginning of the SRS, SR 3.8.1.1 through SR 3. 8. 1. 20 are applicable only to the Unit 2 AC sour.ces and SR 3.8.1.21 is applicable only to the Unit 3 AC sources.
Whe:r;e the S'Rs d,iscus,sed her.ein speci!y voltage an<;l. frequency tolerances, the following summary is applicable.          The minimum steady state output voltage of 4160 V corresponds to the minimum steady state voltage analyzed in the PBAPS emergency DG voltage regulation ~t~dy.        This value allows for voltage drops to motor.s and other equipment down through the 120 V level.      The specified maximum steady state output voltage of 4400 Vis equal tot.he maximum steady state opera.ting voltage specifl.ed for 4000 V mo~ors.      It ensu,tes that for a lightly loaded distribution system, the voltage at the terminiilS of 4000 V motors is no more than the maximum rated steady state operating voltag~s.        The specified minimum and maxi.mum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively.        These values are equal to+/- 2% of the 60 Hz nominal frequency and are derived from the. recommendations fouh~ i~ Regulatory Gvide 1,9 (R~f. 3).
The surveillance requi.rement allowance of :t 2% for the EDG frequency is intended to allow for EDG transient operations during testing.* The nominal frequency value of 60 Hz is credited in plant analyses for ECCS per:f;ormance.
I                                                                          (continued}
PB.APS UNIT 2                        B 3.8-18                      Revision Nq. 71
 
AC Sources-Operating B 3.8.1 I BASES SURV EI LLAN CE SR 3, 8.1.1 REQUIREMENTS (continued)  This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution.buses and loads are connected to their preferred power source and that approprtate independence of offsite circuits ,s maintained.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
SR 3.a,1,2 and SR 3.8,1,7 These SRs help to ensure the availability of the standby electrical pbwer supply to mitigate DBAs and transients and ma1ntain the unit in a safe shutdown condition.
To minimize the wear on moving parts that do not get lubric~ted when the engine is not running, these SRs have I                been modified by a Note (Note 2 for SR 3.8.1.2 and Note 1 for SR 3.8.1.7) to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period and followed by .a warrnup prior to loading.
For the purposes of_ this testing, the  Gs are started from standby conditions. Standby conditions for a DG mean that the diesel engine coolant and oil are being continuously circulated and temperature is being mairrtained consistent with manufacturer recommendations.
In order to reduce str~ss and wear on diesel engines, the manufacturer recommends a modified start in.which the starting speed of  Gs is limited, warmup is limited to thfs lower speed, and the DGs are gradua1ly accelerated to synchronous speed prior to loading. These start procedures are the intent of Note 3 to SR 3.8.1.2, which is Only applicable w~en such mo4ified start procedures are recommended by the manufacturer.
SR 3.8,1.7 requires that the DG starts from standby conditions and achieves required voltage and frequency within 10 seconds. The minimum v,oltage and frequency stated i~ the SR are those necessary to ensure the g
PBAPS UN IT 2                    B 3.8-19                    Revision No. 86
 
AC Sources-Operating B 3.8.1 I          BASES SURV EI LLAN CE      SR 3.8.1.2 and SR 3.8,1.7                        (continued)
REQUIREMENTS DG can accept OBA Toadfng while maintaining acceptable voltage and frequency levels*. S'tabTe operation at the nominal voltage and frequency values is ~ls0 essential to establishing DG OPERABILITY, but a time constraint is not imposed. This is because a typical DG will experience a period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not damped out by load application. The surveillance requirement allowance of +/- 2% for the EOG frequency is intended to allow for EOG transient operations during testing. The nominal frequency value of 60 H.z is credited in plant analyses for ECtS performance. This period may extend beyond the 10 second acceptance criteria and could be a cause for failing the SR. In *11.eu of a time constraint fn the SR, PBAPS will monitor and trend the actual time to reach steady state operation as a means of ensuring there is no voltage regulator or governor degradation which could cause a OG to become inoperable. The 10 second start requirement supports the assumptions in the design basis I'
J LOCA analysis of UFSAR, Section 8.5 (Ref. 10). The U) secorid start re.quirement is not applicable to SR 3 .. 8.1.2 (see Note 3 of SR 3.8.1.2), w.hen a modified start procedure as described above is used. If a modified start is not
- - - - - - - - - --~-----trS--ea,----t-fl e--+0"--s-e \;"Gn d--s--t"itrt-r e tl ti-'l rem e fl-t--e-f--SH~-;-8-;-l-;;-1-a-p p-l-+e s,-. ~ - --
Si nce SR 3 . 8 . 1. 7 re q ui res a 1 0 s e con d s t a rt , it i s mo re restrictive than SR 3.8.l.2j and it may be performed tn lieu of SR 3.8.1.2. This procedure is t~e intent of Note 1 of SR 3.8.1.2.
To minimize testing of the  Gs, Note 4 to SR 3.8.1.2 and Note 2 to SR 3.8.1.7 allow a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met ~Y performing the test on either unit, If the DG fails one Of these Surveillances, the DG should be considered inoperable on both units, unless the cau.se of the failure can be directly relate.d to or:ily one unit.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
I PBAPS UN IT 2                                  B 3.8-20                                          Revision N0 ..86
 
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE          SR    3,8.1.3 REQUIREMENTS (continued)        This Surveillance verifies that the DGs are capa'ble of syn c hr on i z i ng and a c cept i ng a 1oad a pp r ox i ma t e 1y eql'.l i val e nt to that corresponding to the continuous rating. A minimum run time of 60 minutes is re qui red to stabilize engine temperatures, while miriimi.zing th.e time that the DG is connected to the offsite source.
This Surveillance verifies, indirectly, that the DGs are capable of synchronizing and accepting loads equivalent to post acci cieht loads. The DGs a re tested at a 1oad approximately equivalent to their continuous duty rating, even though the post ac*cident loads exceed the continuous r at i ng . Th i s i s a.cc e pt abl e be ca us e reg u1a r s ur ve i 11 a nce testing at post accident loads is injuri*ous t'&deg; the DG, and imprudent because the same leve1 of assurance in the ability of the DG to provide post accident loads can be developed by monitoring engjne parameters during survei1lance te.sti.ng.
The values of the testing parameters can then be qualitatively compared to expected.values at post accident I                      engin~ loads. In making this comparison it is necessary to consider the engine parameters as interrelated indicators of remaining DG capacity, rather than independent indicators.
The important engine parameters to be considered* in makihg
              ---th-ts---compc1T>n-orr--i rrc17Tde, fuel racl(posfffon, scaven-g~i_n_g_a-'i,--r-~--
pressure, exhaust temperature and pressure, engine output, jack-et water temperature, a*nd lube oil temperature. With the DG operating at or near continuous rating and the observed values of the above parameters less than expected post accident value.s, a qualitative extrapolation which shows the DG is capable of accepting post accident loads can be made without requiring detrimental testing.
Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between a.a Tagging and 1.0. The 0.8 value is the design rating of the machine, while 1.0 is an operational limitation. The load band is provided to avoid routine overloading of the DG. Routine over1oading may result in more frequent teardown jnspections 1n accordance with vendor recommendations in order to maintain DG OPERABILITY.
The Surveillance Frequency is controlled under the.
Su rve i Tl a nee Frequency Cont r0 l Program .
~
PBAPS UN IT 2                                B 3.8-.21                              Revision No. 86
 
AC  Sources-Operating B 3. 8 .1 BASES SURVEILLANCE        SR  3,8.1.3. (continued)
R.EQU I REM EN TS Note 1 modifies this Surveillance to indfcate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesil engine are mini mi zed.
Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test. Similarlyj momentary power factor transients above the 71 mit do not invalidate the test.
Note 3 indicates that this Surveillance should be condutted on only one DG at a time in order to avoid common ca.use failures that might resu.lt from offsite circuit or grid perturbations.
Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.
I                              To minimize testing of the DGs, Note 5 allows a single test (instead of two tests, one for each uriit) to satisfy the requirements for both units, with the DG syhchroni zed to .the
--~--~---~----~-~4...,..,...kV-eme ~&sect; e fl ey -b:tJ-s- -of--U n-'i-t-2----fo-r-o n-e----p-e-r i-o-d-tc-t~a-n d- -~
synchr-0nized to the 4 kV emergency bus of Unit 3 during the
                            ~ *next periodic test.        Thfs is allowed since the main purpose of the Surveillance, to ensure DG OPERABILITY, is sti.ll being verified on the preper frequency, and each unit's breaker control circuitry, which is only being tested every second test (due to the staggering of the tests),
historically have a very low failure rate. Note 5 modifies the specified frequency for each unit's breaker control circuitry to the total of the combined Unit 2 and Unit 3 frequencies. If the D~ fails one of these Surveillances, the DG should be considered inoperable on both units, unle*ss the cause of the failure can be directly related to only one unit. In addition, if the test is scheduled to be performed on Unit 3, and the: Unit 3 TS al 1 owance that provides an exception to performing the test is used (i.e., wh*en Unit 3 is in MODE 4 or 5, or moving irradiated fuel assemblies in the secondary containment, the Note to Unit 3 SR 3.8.2.1 provides an exception to performing this test) or if it is not preferable to perform the test on a unit due to operational concerns ( however time is hot to ex..ceed the
* total combine~ frequency plus grace), then the test shall be performed synchronized to the Unit 2 4 kV emergency bus.
PBAPS    UN IT 2                        B 3.8-22                                      Revision No. 86
 
AC Sources-Operating
** BASES B 3.8.1 SURVEI LLAN,CE      SR  3,8,1.4 REQU I R.EMENTS (continued)        This allowance is acceptable provided that the associated unit's breaker control circuitry portion of the Surveillance is performed within the. total combi:ned frequ,ency plus SR 3.0.2 allowed grace period or the next scheduled Surveillance after the Technical Specification a11Qwance is no longer applicable.
* This SR provides verification that the level of fuel oil in the day tank is adequate for a minimum of 1 hour of DG operation at full load. The level, whi'ch includes margin to account for the unusable volume of oil, is expressed as .an equiivalent volume in gallons.
The Surveillance Frequency is controlled under the Survei 11 ance Frequency Control Program.
SR  3,8.1.5 Microbiologfcal fouling is a major caus.e of fuel oil degradatio~. T~ere are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Periodic remova.l of water                                                            I
                  -~~f-r- Gm-Ul 8----c----f.u 8-+---o.:i-1-da;y-t a.n..k.s.......e.:J .:i..m.i .r:i at.e.S--th e-r:i e.c e.s..s..a,r..y - - - - ___ ,
environment for bacterial survival. This is the most effective means of corit~olling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system.
The Surveil~ance Frequency is controlled under the Surveillance Frequency Control Progr,am. This. SR is for preventive maintenance. The presence of water does not necessari.ly represent a failure .of this SR provided that accumulated water is removed during performance of this Survefl lance.
SR  3.8.Lv This Survei 11 ance demonstrates that each require.ct fuel 01 l transfer pump operates and automatically transfers fuel_oi1 from its associated storage tank to its associated day tank.
It is required to support continuous operation of standby power soarces. This Surveillance provides assurance that PBAPS UN IT 2                                        B 3. 8-23                                                    Revision No. 86
 
AC Sources-Operating B 3,8.1 I  BASES SURVEILLANCE SR 3,8.1.6 (continued)
REQUIREMENTS the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE.
This SR is modified by a Note. The note recognizes that manual actions for manually operating local hand valves and control switches associated with the DG fuel oil transfer system is limited to support transferring fuel between DGs, testing, and sampling activities. These manual actions would promptly restore the EDG fuel oil system to an automatic status since the actions are simple and straightforward. Credit for manual operator actions for maintaining operability mwst be controlled procedurally.
These actions include a dedicated qualified individual and constant comrm:mication With main control room licensed personnel.
The Surveillance Frequency is controlled under the I .
Surveillance Frequency Control Program .
                                                          .........____._- . -~--------.--.,..--,...--
transfer of each 4 kV emergency bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the shutdown loads. The Surveillance Frequency is co~trolled under the Surveillance Frequency control Program.
This SR is modified by a Note. The reason for the Note is that, daring operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant
                ~afety systems. This Surveil1ance tests the applicable logic associated with Unit 2. The comparable test specified in Unit 3 Technical Specifications tests the applicable logic associated with Unit 3. Consequently. a test must be pe.rformed within the specified Frequency for each. unit. As the Surveillance represents separate tests, the Note (continued)
PBAPS UNIT 2                  B 3.8-24                          Revi$ion No. 139
 
AC Sources - Operating B 3.,8.1 BASES
' SURVEILLANCE REQUIREMENTS SR 3,8.1,8 (continued) specifying the restriction for not perfonning the test while the unit is in MODE 1 or 2 does not have app 1icabil i ty to Unit 3. The Note only applies to Unit 2, thus the Unit 2 Surveillance shall not be performed with Un.it 2 in MOOE 1 or
: 2. Credit may be taken for unplanned events that satisfy this SR.
SR 3,8, 1.9 Each DG is provided with an engine overspeed tri.p to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engi1ne overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding pr-edetennined voltage and frequency and while maintaining a specified margin to the overspeed tri.p. The 1arg,est single load for each DG is I              a residual heat removal pump (2000 bhp). This Surveillance may be accomplished by~ 1) tripping the DG output breakers with the DG carrying. greater than or equal to its associated single largest post-accident load ~hile paralleled to
_______offsitELp.ower~-0t-whjJe--Sole.~supP-l--y-ing-the----bu~,---0r-2~-~-
tripping its associated single largest post-accident load with the DG solely supplying the bus. Currently, the second option is the method PBAPS ut 11 i zes because the first method will result in steady state operation outside the allowable voltage and frequency limits. Consistent with Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the diesel speed does not exceed the nominal (synchronous) speed plus 75% of the difference between nominal speed and the overspeed trip setpoint, or 115%' of nominal speed, whichever is lower.
The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref. 3) reconwendations for response during load sequence intervals.
The 1.8 seconds sp~cified for voltage ind the 2.4 seconds specified for frequency are equal to 60% and 80%,
respectively, of the 3 second load ,sequence interval associated with sequencing the next load following the residual heat removal (RHR) pumps duri'ng an undervoltage on the bus concurrent with a LOCA. The voltage and frequency specified are consistent wtth the design range of the (continued)
PBAPS UN1T 2                  B 3.8-25                      Revision No. 1
 
AC S0urces -Operating B 3.8.1 BASES SURVEILLANCE        SR      3.8.1.9        (continued)
  .R:EOU IREMENTS equipment powered by the DG. SR 3 .,8 .1. 9. a corresponds to the maximum frequency excurs1orr, while SR 3.8.1.9.b and SR 3.8.1.9.c provide steady state voltage and frequency values to which the system must recover following load rejection. The surveillance requirement allowance of+/- 2%
for the EDG frequency is intended to allow for EDG tra~sient operations during testing. The nominal frequency value of 60 Hz is credited in plarrt analyses for ECCS performance.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
This SR is modified by two Notes. Note 1 ensures that the DG is tested under load conditions that are as close to design basis conditions as possible. When synchronized wi~h oftsite power,* testing s~ould be performed at a power factor of s 0.89. This power factor is representative of the actual inductive loading a DG would see ~nder design basis accident conditions. Under certain conditions,- however, N.ote 1 allows the Surveillance to be conducted at a power factor other than I                      ~ 0.89.          These conditions occur when grid voltage fs high, and the additional field excitation needed to get the power factor to s 0.89 results in voltages on the emergeocy busses that are too high. Under these conditions, the power factor
            - ------s-l=l-0 l:l~-0---e e--m a4-n--c-a+l'l ee-------a-s---c-l- e s-e--a-s-p--r-act-+-ca-b-1-e-t-o-G-:-B 9---w ttrl *e still maintai,ning acceptable voltage limits on the emergency busses. In other cireumstances, the grid voltage may be such that the DG excitation levels needed to obtain a power factor of O. 89 may n*ot cause unacceptable vol tag es on the emergency busses, but the excitation levels are in excess of those recommended fo~ the DG. In such cases, the power factor shall be maintained-as c*lose as practicable to 0.89 without exceeding the DG excitation limits.
To minimize testing of the DGs, Note 2 allows a single test (instead of two tests, one for each unit) to satisfy the requi. rements for both units. This i. s a 11 owed si nee the ma i r'l purpose of the Surveillance can be met by performing .the test on either unit. If the DG fails one of these Surveillancesj the DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit.
,                                                                                                                    ( cont i nue,d)
PBAPS UN IT 2                                                                                            Revtsion No. 86
 
AC Sources-Operating B 3-.8.1 BASES SURVEILLANCE      SR    3.8.1.10 REQUIREMENTS Consistent with Regulatory Guide 1.9 {Ref. 3),
paragraph C.2.2.8, this Surveillance demonstrates the DG capability to reject a full load without oversfeed tripping
                  *or exceeding the predetermined voltage limits. The DG full load rejection may occur because of .a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load respon~e under the simulated test conditions. This test simulates the loss of the total com,ected load that the DG experiences following a full load reje~tion and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide DG damage protection. While the DG is not expected to experien-ce this transient during an event, and continue to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bu~ if the trip initfat0r carr be corrected or isolated.
The Surveill~nce Frequency 1s controlled under the Surveillan:ce Frequency Control Program.
This SR is modified by two Notes. Note 1 ensures that the DG is tested under load conditions that are as Close to design basis conditions as possible. When synchroniz~d with
                --o rfsH-e---power-;-testtng-s-hot.rld-b*e-p-erformett,rt-a-vowe-r-fcr-ct*crr~--
of :s; 0.89. Tbis power factor is representative of the actual inductive lo ading a DG would see under design basis 0
accident conditions. Under ce,rtai n conditions, however, Note 1 allows the Surveillance to be conducted at a power factor other than~ 0,89. These conditions occur when grid voltage is nigh, and the additional field excitation needed to get tl:ie power factnr to~ 0.89 results in voltages on the emergency busses that are too high. Under t,hese condi.tions, the power factor should be matntained as close as .
practicable to 0.89 while still maintaining acceptable voltage limits on the emergency busses. In other circumstances, the grid voltage may be such that the DG excitation levels needed to obtain a power factor of 0:89 may not cause unacceptable voltages on the emergen.cy busses, PBAPS UN IT 2:                      B  3.8-27                        Revision No. 86
 
AC Sources-Operating B 3.8.1 I  BASES SURVEILLANCE        SR 3,8,1.lQ (conti~ued)
REQUIREMENTS but the excit~tion levels are in excess of those recommefided for the DG. In s.uch cases, the power factor shall be maintained as close as practica.ble to D.89 without exceeding the DG excitation limits. To minimize testing of th,e, DG.s, Note 2 allows a single tes.t (instead of two tests, one for each unit) to satisfy the requirements for both uni ts. This is allowed since the main purpose of the Surveillance can be met by performing the test on either unit. If the DG fails one of these Survei 11 ances, th.e DG should be considered i nope r ab l e on both un. its , un1 es s the c a us e of the. fa i l ure can be directly related to only one unit.
SR 3.8.1.11 Cons is.tent wHh Regulatory Gui de 1. 9 (Ref. 3),
paragraph C.2.2.4, this Surveillance demonstrates the as designed operation of the standby power sources during loss*
of the offsite source. This test verifies all actions I                    encountered from the loss of offsite power, including shedding of a 11 loads and .energization of the emergency buses and respective loads from the DG. It further demonstrates the capability of the DG to automa~ically
                ---Y* c bJ.eJ,t,-tl:1 a- 1c-e q u--i- r--e d---v-e+t--a &sect; e---a-n cl-,-fr e ff uen e-y-wfth+-n-t-h-e- --
spec Hied time.
The DG auto-start and energization of the associated 4 kV emergency bus time of 10 seconds is derived from re.qui rements of the accident analysis for responding to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes 'in order to demonstrate
                    -that all starting transients have decayed and stability has been achieved ..
(continued)
PBAPS UN IT .2                                    B 3.8-27a                                            Revision No. 51
 
AC Sources-Operating B 3.8.I I BASES SIJRVEI LLANCE SR      3 , 8 , 1. 11 ( cont i nu ed )
REQU1 REMENTS The requirement to verify the connection and power supply of auto-connected loads is intended to satisfactorily show the relationship of th.ese loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected, or loaded *without undue hardship or pote.ntial for undesired operation. For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or systems are not capable of being operate~ at full flow, or RHR systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of t he conn e ct i ll n a nd l oa di ng of t he s e l O*a ds , t es t i ng t ha t adequately shows the capability of the DG system to perform these function~ is acceptable. This testing may fnclude any S'e r i es of s e quen t i al , ove r l a pp i ng , o r tot a l s t ep s s o t ha t the entire connection and lo-acting sequence is verified.
The Surveillance Frequency is controlled under the Survei 11 ance Frequency Control Program.
I                This SR is modifted by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs shall be started from s+a oob-y-e0 nd-'i-t-i-0 AS,-t-8-a-t---4-s- ,W4-t-h-t-A e----e,n gln e--c--<w-1-a n-t----a'fl EI--G.:i - -
being continuously circulated and temperature maintained
                                                                                                                              -~
cons*i stent with manufacturer recommendations. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from servf ce., perturb the electrical distribution system, and chc:)1lenge safety systems. This Survei 71 ance tests the appl i c--0.bl e. logic associated with Unit 2. The comparab1e test specified in the Untt 3 Technical Specifications tests the applicable logic associated with Unit 3. Consequently, a test must be performed within the speci fi'ed Frequency for each un.it. The surveillance requirem"nt allowance of+/- 2% for the EOG frequency is intended to allow for EOG transtent operati.ons during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performan~e. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2, or 3 does not have applicability to Unit 3.
The Note only applies to Unit 2, thus the Unit 2 Surveillances shall not be performed with Unit 2 in MOOE 1, 2, or 3. Credit may be tak.en for unplanned events that I
satisfy this SR.
PBAPS UN IT 2                            B 3.8-28                                      Revision No. &6
 
Ac Sources -Opei;atihg B 3.8.1 BASES SURVEILLANCE REQUIR_EMENTS      SR    3. B. 1. 12 (contihUed)
Consistent with Regulatory Guide 1.9 (Ref. 3),
paragraph, C.2.2.5, this Surveiilance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time HO seconds) from the design basis actuation signi;l-1 (LOCA signal) and operates for;;: 5 minutes. The minimum voltage and frequency stated in the SR are those necessary to ensure the DG can accept DBA loading wnile maintaining acceptable voltage and f:r::equency levels. Th,e surveillance requirerneht allowance of
                                +/- 2% for the EDG frequency is fhtended to allow for EDG transient operations during testing.          The. nominal frequency value of 60 Hz is credited in plant analyses for ECCS pertorrnance.      Stable operation at the nominal voltage and frequency values is also essential to establishing DG OPERABILITY, but a time* constraint is not imposed.                    This is because a typical DG w.ill experience a t)eriod of voltage and frequency oscillations prior to reaching steady state operation if thes*e oscillations are not, damped out by load application.      This period may extend beyond the 10 second acceptance criteria and could be a cause for fail,lng the SR.
In lieu of a time constraint in the SR, PBAPS will monitor and trend the actual time to reach steady state operation as a means of ensuring there ~s no voltage regulator or
- - - - - - - ~ - - - - ~ __.__ go.v.ernor-degr.ada.twn_.whl ch_.could-.eause-a.....J:iG.-tQ.- become inoperable. The 5 minute period provides suff.icient time to demonstrate stability.      SR 3.8,1.12.d and SR.3.8.1.12.e ensure that permanently connected loads and emergency loads are energized from the offsite electrical power system on a LOCA signal without loss of offsite power.
The requirement to verify the connection and power supply of permanent and autoconhected loads is intended to satisfactorily show the relationship of these loads to the loading logic for loading onto o:ffs:ite power.                In certain circumstances, ITI.?PY of* these loads can.not actually be connected or loaded without undue hardship or potential to:r::
undesiree. operation.      for instc;111-ce, ECCS injection valves are not desired to be. stroked open, '.ECCS. systems are not capable of being operated at full flow, or RBR 'Systems performing a decay hea,t .r;emoval function are not desired :to be realigned to the ECCS mode of operation.                  In lieu of actual demonstration of the connection and loading of these loads, testing that adequately shows the capability of the DG system to pe:r::form these :functions is acceptable.                This testing: may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is ver.ified.
( cont*inued)
PBAPS UNIT  2                          B 3.8-29                              Revision No.      71
 
AC Sources-Operating B 3.8.1 I  BASES SURVEILLANCE      SR 3.8.1,12                  (continued)
REQUIREMENTS The Surveillance trequency is controlled under the Surveillance Frequency Control Program.
This SR is modified by a Note.* the reason for the Note is to minimize wear and tear on the DGs during testing. For
* the purpose of this te*sti ng, the DGs must be started from standby conditions, that is, with the engine coolant and Oil being continuously circulated and temperature maintained consistent with mijnuf~cturer recommendations.
SR 3.8.1.13 Consistent with Regu1atory Guide 1.9 (Ref. 3),
paragraph C.2.2.12, tbis Surveillance demonstrates that DG noncritical protective functions (e.g., high jacket water temperature) are bypassed on an ECCS initiati~n test signal.
Noncritical automatic trips are all autornati'c trips except:
engine overspeed, generator differential overcurrent, generator ground neutral overcurrent, and manual tardox initiation. The noncritical trips are bypassed during OBAs and continue to provide an alarm On an abnormal engine condition. This alarm provides the operator with sufficient
  ---------~,.....t--Liimuu..e__t_Q____fj:_fil;~LaP-P__r__o_pr_i ate l v , _ The DG a Va i l ab i Tii'L._1~-~ ____ - ~
mitigate the OBA is more critical than protectin~ the engine against minor problems that are not irnniediately detrimental to emergency operation of the DG. DG emergency automatic trips will be tested periodically per the station periodic maintenance program.
The Survei l 7ance Frequency is controlled under the Surveillance Frequency Control Program.
To minimize testing of the DGs, the Note to this SR allows a single te.st (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the ma1n purpos~ of the Surveillance can be met by performing the test on either unit. If the DG fails one of these Surveillances, th.e DG should be considered inoperable on both units, unless the cause of the failure can be directly related to only one unit.
PBAPS UNIT 2                                      B 3.8-30                                  Revis:'Jn No. 86*
 
AC Sources-Operating B 3.8.1 BASES
'  SURVEILLANCE REQUIREMENTS (continued)
SR  3,8.1.14 Consistent with Regul.atory Guide 1.9 (Ref. 3),
paragr.aph C.2.2.. 9, this Surveillance re.quires demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours.
However, load values may deviate. from the Regulatory Gui.de such that the DG operates for 22 hours at a load approximately equivalent t0 .92% to 108% of the contin*uous duty rating of the DG, and 2 hours of which is at a load approximately equivalent to 108% to 115% of the continuous duty rating of the DG. The DG starts for this Surveillance can be performed either from standby 0r hot conditions. The provisions for prelub~ and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.
This Surveillance verifies, indirectly, that the DGs are capable of synchronizing and accepting loads equivalent to post accident loads. The DGs are tested at a load approximately equivalent to their continuous duty rating, even though the post accident loads exceed the continuous rating. This is acceptable betause regular surveillance testing at post accide.nt load*s i.s injurious to the DG, and imprudent because the. same level of assurance in the ability
              ~---of-th 8-----DG~tG---p r-ov4--de--p,est-a e::e:ii:I e n-t--7-oa cl s---c-a:n--be-d ev e*}op ed---b-y---- -- ---
monitoring engine parameters during survei 11 ance testing.
The values of the testing parameters can then be qualitatively comp.ared to expected values at post accident engine loads. In making this comparison it 9s necessary to consider the engine parameters as interrelated indicators of remaining DG tapacity, rather than independent indicators, The important engine parameters to be considered in making this comparison include, fuel rack position, scavenging air pressure, exhaust temperature and pressure, engine output, jacket water temperature, and lube oil temperature. With the DG operating at or near continuous rating and the observed values of the above p,arameters less than expected post attident values, a qualitative extrapolation which shows the DG is Gapable of accepting post accident loads can be made without requiring detrimental testing .
~.
co tine PBAPS UN IT 2                            B 3,8-31                                        Revision No. 57
 
AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR  3.8.1,14  (continued)
REQUIREMENTS A lead band is proviMd to avoid routine overlo.ading of the DG. Routine overloading may result fn more frequent teardown inspections fn accordance with vendor recommendations in order to maintain OG OPERABILITY.
The Surveil1ance Frequency is controlled ~nder the
              $urvei 11 ance Freqoency Control Program.
This Surveillance has been modified by three Notes. Note 1 state~ that momentary transients due to chijnQing bus loads do not invalidate this test. Similarly, momentary power factor transie~ts above the limit do not invalidate the test. Note 2 ensures that the DG is tested under load conditions that are as close to design basis conditions as possible. When synchronized with o-ffsite power, testing should be performed at a power factor of s 0.89. This power factor is representati~e of the actual inductive loading a DG would see under design basis accident conditions. Under certain conditions, however, Note 2 allows the Surveillance to be tonducted at a power factor other than s 0.89. These conditi ans occur when grid voltage is high, and the additional field excitation needed to get the power factor to .s O.89 resul'ts in voltages 0n the ,emergency busses that are too high. Under tnese conditions, the power factor should be ~aintained as close as practicable to 0.89 while I              still maintaini~g acceptable voltage l1mits on the emergency busses. In other c1rcumstances, the grid voltage may be such that the DG excitation levels needed to obtain a power factor of 0.89 may not cause unacceptable voHages on the emergency busses, but the excitation levels are in excess of those recommendeo for tne ~~In sucn cases, tnepower factor shall be maintained as close as practicable to 0.89 without exceeding the DG excitation limits. To minimize testing of the D&s, Note 3 allows a single test (instead of two tests, one for e,n:h unit) to satisfy the requirements for both units. This is allowed since the main purpose of the Surveillance can be met by performing_the test on either unit, If the DG fails one of these Surveillances, the DG strould be c0nsidered inoperable on both units, unless the.
cause of the failure can be directly related to only one unit.
SR  3,8,1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 10 seconds. The minimum voltage and frequency stated ih the SR are those necess.ary to ensure the DG can accept DBA loading While maintaining acceptable voltage and frequency levels. Stable operation at the nominal voltage and frequency values is also essential to establishing DG OPERABILITY, but a time constraint is not imposed. This is becau:_se a typical DG will experience a PBAPS UNIT 2                    B 3.8-32                    Revision No. 86
 
AC Sotlrces -OpHat i ng B 3.8.1 BASES SU RV Ell.LANCE SR 3 , 8 , 1. 15  ( cont i n ued )
REQUIREMENTS period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not damped out by load appl t.cat ran. The survei TJ ance-requi rement allowance of+/- 2% for the EOG frequency is intended to allow for EOG transient operations-during testing. The nominal frequency value of 60 Hz is cred1ted in plant analyses for ECCS performance. This period may extend beyond the 10 second acceptance criteria and could be a cause for failing the SR. Ln ~ieu of a time constraint in the SR, PBAPS w-ill monitor and trend the actual time to reach steady state operation as a means of ensuring there ~s no voltage regulator or governor degradation which could cause a DG to become inoperable. The 10 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance Frequency is controlled under the Surveillance Frequency Contro.l Program.
This SR is modified by three Notes. Note 1 ensures that the test is performed w.ith the di es*e1 suffi ci entl y hot. The requirement that the diesel has ope-rated for at least 2 hours at full load conditions prior to performance of this Survei 11 a rice is- based on manufacturer recommendations for a chi evi ng hot conditions. The load band is provided to
  --~-~-----~~----  av oi d routine over l 5a1I 1 ng 0f -t1ie--o-G-:""-Ruatt ne-uve r-i-ocrd ~-~ -
result in more frequent teardown inspections iri accordance with vendor recommendations in order to maintain OG OPERABILITY. Momentary transients due to changing bus loads do not inval9date this test. Note 2 allows all OG starts to be preceded by an engtne prelube period to minimize wear and tear on the diese~ durtng testing. To minim1ze testing of the DGs, Note 3 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both u.nits. This is allowed s9nce the main purpose of the Surveil1ance can be met bY performing the test on either unit. If the DG fails one of these Surveillances, the DG should be considered inoperable on both units, unless the cau.se of the failure can be directly related. to only one unit.
SR    3,8.1.16 Consistent with Regulatory Gui de 1. 9 (Ref. 3),
paragraph C.2.2.11, this Surveillance ensures that the manual synchronization and load transfer from the DG to the offsite source can be made and that the DG can be returned PBAPS UNIT 2                          B  3.8-33                            Revision No. 86
 
AC Sources -Operating B 3.8.1 I      BASES SURVEILLANCE      SR    3.8.1.16 * (continued)
REQUIREMENTS to ready-to-load status when offSite power is r~stored. It also ensures that the auto-start logic is reset to allow the DG to reload if a subsequent loss of off site power occurs.
The DG is considered to be in ready-to-load status when the DG is at rated speed and voltage, the output breaker is open and c:an rec:eive an auto-close signal on bus undervoltage, and individual load timers are reset.
The Surveillance Frequency is controlled under the Surveillance Frequency Contro1 Program.
This SR is modified by a Note. The reason for th,e Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the lectrica1 distribution system, and challenge safety systems. This Surveillance tests the applicable logic associated witn Unit 2. The comparable test specified in the Unit 3 Tec hni c a1 Spec i f i ca f i O'n s t e s t s t he app 1i ca b1e 1ogi c associated with Unit 3. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate te~ts, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2. or 3 does not have applicability
~ - ~ ~ ~ - - - ~-----.---t O- Unil -3 __JJie._Jw.te____onJ.y _a p_pJJ..es._to Un it 2 ,__:tb_l,Ls the Un it 2 Surveillances shall not be performed with Unit 2 in MOD~ 1, 2, or 3. Credit may be taken for unplanned events that satisfy this SR.
SR    3,$.1.17 Consistent with Regulatory Guide 1.9 (Ref 3),
paragraph C.2.2.13, demonstration of the test mode override ensures that the DG availability under accident conditions is not compromised as t~e resu1t of testi~g. Interlocks to the LOCA sensing circuits cause the DG to automatically reset to ready-to-load operation if a Unit 2 ECCS initiation signal is received during operatio.n in the test mode while synchronized to either Unit 2 pr a Unit 3 4 kV emergency bas. Ready-to-load operation is defined as the DG running at rated speed and voltage with the DG output breaker open.
PBAPS UNIT 2                                                                        Revision No. 86
 
AC Sources-Operating B 3.8.1
'          BASES SURVEILLANCE REQUIREMENTS SR  3.8.1.17    (continued)
The requirement to automatically energize the emergency loads w1th offsite power ensures that the emergency loads will connect to an offs1te source. This is performed by e.nsuring that the affected 4 kV bus remains energized following a simU1ated LOCA tr1p of the DG output breaker, and ensuring 4kV and ECCS logic performs as designed to connect all eme,rgency 1oads to an offsite source. The requirement for 4kV bus load1ng is covered by overlapping SRs specif1ed in Spec1f1cation 3.8.1, "AC Sources-Operat1ng" and 3.3.5.1 "ECCS Instrumentation". In lieu of actual demonstration of connection and loading of loads, testing that a.d,equatel y shows the capabi l Hy of the emergency loads to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading is verified.
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
To min1mize testing of the DGS, the Note allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both uni ts. Th1 s is all owed si nee the main purpose ,of the Survei 71 anee ca.n be met by performing the test on either unit. If the DG fails one of these
-~--~-~~------~~".B.illance.s..,._the____fiG__s bouJ_cL be-c;on s.i-d e-r-sd-i--M Gpe-r-a b-le-on-------
bot h units, un1ess the cause of the failure can l:ie directly related to only one unit.
SR  3, 8, 1.18 Under accident and loss of offsite power conditions, load*s a re sequenti a11 y connected to the bus by i ndi vi dua 1 load timers (i.e., relays). The seq.uencing logic col'ltrols the permissive and starting signals to motor breakers in timed load blocks a.s depicted, by example, on Table 8.5.1 of Reference 10 to prevent overloading of the DGs due to high motor starting currents. The desi~n interval for each individual load timer ,s the time between each load block that is applied onto the associated DG and is listed on the example Table 8.5.1 of Reference 10. The 1oad sequence time interval (including the 10% tolerance) ensures that suffic1ent time exists for the DG to restore frequency and voltage prior to applying the next timed load block. This ensures that safety analysis ijssumptions regarding ESF equipment time delays are not violated. Reference 10 pro vi des a summary of the automatic l oa,di ng of emergency buses.
~
PBAPS. UNIT 2                                                      Revision No. 117
 
AC Sources-Operating B 3.8.1 I BASES SURVEI:LLANCE        SR 3.8.1.18          (continued)
REQU LREMENTS The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remov~ a required offsite cir*cuit from service, perturb the electrical distribution system, and challenge safety systems. This Survei 11 ance tests the applicable 1ogi c associ a"ted with Unit 2. The comparab1 e test specified in the Unit J Technical Specifications tests the applicable 1ogi c associated with Unit 3. Consequently, a. test must be performed within the spec1fi ed Frequency for each unit. As the SurveiJlance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2, or 3 does not have applicability to Unit 3. The Note only applies to Unit 2, thus the Unit 2 Surveillances shall not be performed with Unit 2 in MODE 1, 2, or 3. Credit may be taken for unplanned events that satisfy this SR.
SR 3.8.1.19
          --- -- - ------+ri4h e- -e v-e At-0 f.-a----0 BA- Go-i *n E---i d-e nt--w-i -t--h-3/4--l-0&#xa3; s---0-f-- -G--U&,tt B--- ~ - ~
power, the  Gs are required to s.upply the necessc1ry power to ESF systems so that th~ fuel, RCS, and containment design limits are not exceeded.
This Surveillance deJnonstrates DG operation, as discussed in the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ECCS initiation si gna1. In lieu of actual demonstration of connection and loading of lcrads, testing that adequately shgws the capabi 1Hy af the DG system to perform these functions is acceptaDle. This testing may include any series of sequential, overlapping. or total steps so that the entire connection and loading sequence is verified.
The Surveillance Frequency is controlled under the Survei11ance Frequency Control Program.
PBAPS UN IT 2                                    B 3.8-36                                            Revision No. 86
 
AC SoU.tceS-'Operating B 3.8.1 I BASES SURVEILLANCE REQUIREMENTS SR  3.8.1.19    (continued)
This SR is modified by two No'tes. The reason for Note 1 is to minimize wear ang tear on the DGs during testing.        For the purpose of this testing, the DGs ,must be started from standby conditions, that iS', with the engine coolant and oil being continuou,sly circulated and temperature maintained consistent with manufacturer recormtlendation,s. The surveillance requirement allowance of+/- 2% for the EDG frequency is intended to allow for EDG transient operations during testing. The nominal frequency value of 60 Hz is credited in plant analyses for ECCS performance. The reason for Note 2 is that performing the Surveillance would remove-a req,uired offsite circuit; from service, perturb the electrical distribution. system, and challenge safety systems. This Surveillance tests the applicable logic associated with Unit 2. The comparable test specified in the Unit 3 Technical Specifications tests the* applicable logic associated with Unit 3. Consequently, a test must be performed within the specified Frequency for each unit. As the Surveillance represents separate tests, the Note specifying the restriction for not performing the test while the unit is in MODE 1, 2, or 3 does not have applicability to Unit 3. ~he Note only applies to Unit 2, thus the Unit 2 Surveillances shall not be performed with Unit 2 in MODE 1, 2, or 3. Credit may be taken for unplanned events that sa*tisfy this SR.
SR  3.8.1.,20 This Sllrveillance demonstrates that the DG sta,rting independence has hot been compromised. Also, this Surveillance demonstrates that each etrgihe can achieve proper speed within the specified time when the DGs are started simultaneously.
The minimum voltage and fr.equency stated in the SR are those necessary to ensure the DG can accept DBA loading while maintaiaing acceptable voltage and frequency levels. The surveillance requirement allowance of+/- 2% for th~ EDG frequency is intended to allow for EDG transient operations during testing. 1he nominal frequency val~e of 60 Hz is cr,edited in plant analyses for ECCS performance.        Staple operation at the nominal voltage and frequency values is also essential to establishing DG OFERABILITY, but a time constraint is not i_mposed,,  This Ls }:)eca1,1se a typical DG will experience a period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not damped out by loa~ application.
This period may extend beyond the 10 second aoceptance criteria and could }:)ea cause for failing th~ SR.        In lieu of a time constraint in the SR, PBAPS will monitor and trend the ac;tual time to reach steady state operation as a means oi; ensu,rin:g there is no voltage regulator or governor degradation which could cause a DG to beaome inoperable.
(continued)
PBAPS UNIT 2                    B 3. 8"-37                      Revision No. 71
 
AC Sou,rce,s ~Operating B 3.8.l BASES SURVEILLANCE      SR    3,8,1,20        (continued)
REQUIREMENTS Tbe Survei 11 ance Frequency is control 1ed under the Surve111ance Frequency Control Program. This SR is modified by two Notes. The reason for Note 1 is to minimize wear on the DG during testing. ~or the purpose of this testing, the DGs must b~ started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations. To minimize testing of the DGs, Note 2 allows a single test (instead of two tests, one for each unit) to satisfy the requirements for both units. This is allowed since the maih purpos,e of the Surveillance can be met by performing the test on either unit. If a DG fails one of these Surveillances, a DG should be considered inoperable an both units, unless the cau.se of the failure can be directly related to only one unit.
SR    3.8,1.21 I
~~
With the exception of this Surveillance, all other Surveillances of this Specification CSR 3.8.1.1 through SR 3.8.1.20) are applied only to the Unit 2 AC sources.
This Surveillance is provided to direct that the appropriate
  - - ~ - - - - ~ ~ - ~ ~ SUT;-v.B--i +la nce-&------fG~he---r-eq lcl-i-F ed-\J.n~-t---3-AC---s e U--P-&e-s-- a-r-e-~-~---
gover ned by the applicable Unit 3 Technical Specifications.
Performance nf the applicable ,Unit 3 Survei 11 ances wi 11 satisfy Unit 3 requirements, as well as ~atisfying this Unit 2 Surveillance Requirement. Six exceptions are noted to the Unit 3 SRs of LCO 3.8.1. SR 3.B.1.8 is excepted when only one Unit 3 offs1te circuit is required by the Unit 2 Specification, sin.ce there is not a second circuit to transfer to. SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.17, SR 3.8.1.18 (ECCS load block requirements ~nly), and SR 3.8.1.19 are excepted since these SRs test the Unit 3 ECCS initiation signal, which is not needed for the AC sources to be OPERABLE on Unit 2.
The Frequency required by the applicable Unit 3 SR also governs performance of that SR for Unit 2.
As Noted, if Unit 3 is 1n MODE 4 or 5, or moving irradiated fuel assemb11es in the secondary containment, the Note to Unit 3 SR 3.8.2.1 is applicable. This ensures that a Unit 2.
SR will not require a Unit 3 SR to be performed, when the
'        PBAPS UN IT 2                                B 3.8-38                                        Revision No. 86
 
AC Sources-Operating I
B 3.8.1 BASES SURVEILLANCE      ~R 3.8,1,21 (continued)
REQUIREMENTS Unit 3 Technical Specifications exempts performance of a Unit 3 SR (However, as state.ct in the Unit 3 SR 3,8.2.1 Note, while performance of an SR is exempted, tt,,e SR sti 11 mu.st be met).
REFERENCES        1. UFSAR, Sections 1. 5 and 8.4.2.
2'. UF$AR, Sections 8.3 and. 8.4.
: 3. Regulatory Guide 1.9' July 1993.
: 4. UFSAR, Chapter 14.
: 5. Generic Letter 84-15.
: 6. Regulatory Guide 1.93, December 1974.
I .
7.
8.
UFSAR, Section 1.5.1.
Regulatory Guide 1.108, August 1977 .
            ---------9-.--Re-gu+a-t*{lf*y-GuldB-l--:-l--3-7-;-0ctober--19Y~ . - - - - ------------
: 10. UFSAR., Section 8. 5.*
: 11. NEDC-32988*A, Revision 2, Techni'cal Justification to Support Risk-Informed Modification to Selected Required End States for BW'R Plants, December 2002.
: 12.  ~egulatory Guide 1.9 (Safety Guide 9), March 1971.
PBAPS UN IT .2                        B 3 *. 8-39                          Revision No. 95
 
AC Sources - Shutdown B 3.8.2-
* B 3.8 B 3. 8. 2 BASES ELECTRICAL POWER SYSTEMS AC Sources- Shutdown BACKGROUND            A description of the AC souroes is provided in the Bas~s for LC0 3.8.1, "AC Sources-Operating."
APPLICABLE            The OPERABILITY of the minimum AC sources during MODES 4 SAFETY ANALYSES      and 5 and during movement of irradiated fuel assemblies in secondary containment ensures that:
: a. The facility can be maintained in the shutdown or refueling condition for extended periods;
: b. Sufficient instrumentation and control capability is available for monitoring and maintaining the unit status: and
: c. Adequate AC electrical power is provided to mitigate events postulated durjng shutdown, such as a fuel handling accident .
In general, when the unit is. shut d0l'.JJLthe_ Teci1n.i-e-a+---------~-----~-
Spec1 f 1cat1 ons requirements ensure that the unit has U1e capability to mj ti gate *the consequences of postulated
                      -.accidents. However, assuming a single failure and
                      * -~bnturrent loss of all offs1te or loss of all onsite power is not required. The rationale for this is based o~ the fact that many Design Basis Accidents ( DBAs) that a re analyzed in MODES 1. 2, and 3 have no specific analyses in MODES 4 and 5. Worst case bounding events are deemed ~ot credible in MODES 4 and 5 because the energy contained within tha reactor pressure boundary, reactor coolant tempe.rature a*nd pressure, and corresponding stresses result in the probabilitfes of occurrences signtficantly reduced or eliminated, and minimal consequences. THese dev~ations from OBA analysis assumptions and design requirements during shutdown conditions are allowed by the LC0 for required systems.
During MODES 1, 2, and 3, various deviations from the analjsis assumptions and design requirements are allowed within the ACTIONS. This allowance is in recognition that
* PBAPS UN IT 2                            B 3.8-40                    Revision N-0. 145
 
Ac Sources---Shutdown B 3.8.2 BASES APPLICABLE      certain testing and matntenance activities must be SAFITY ANALYSES conducted,. provi dad. an acceptable. level of risk is not (continued)  exceeded. During MODES 4 and 5, performance of a significant number of required testing and maintenance activities is also required. In MODES 4 and 5, the activities are gene.r.ally planned and administratively contro1led. Relaxations from typi'cal MODES 1, 2, and 3 LCO requirements are acceptable during shutdown .MODES, based onr}}

Latest revision as of 09:34, 29 November 2024

Submittal of Changes to Technical Specifications Bases
ML21118A057
Person / Time
Site: Crane Constellation icon.png
Issue date: 04/13/2021
From: David Helker
Exelon Generation Co
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
TMl-21-012
Download: ML21118A057 (795)
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