ML18038B754

Proposed Conversion from Current TSs to Improved STS Consistent w/NUREG-1433,rev 1

ML18038B754
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Site:	Browns Ferry
Issue date:	09/06/1996
From:	TENNESSEE VALLEY AUTHORITY
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RTR-NUREG-1433 NUDOCS 9609190176
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BR()WNS FR~V NUCLEAR PLANT Ill'W'"tel t~F Date c of Utr Regulator Docket File Enclosure I Volume 1 9609'i90i76 '760906 PDR ADOCK 05000259 P PDR

BROWNS FERRY NUCLEAR PLANT APPLICATION OF SCREENING CRITERIA CONTENTS

1. INTRODUCTION

2. SCREENING CRITERIA

3. PROBABILISTIC RISK ASSESSMENT INSIGHTS

4. RESULTS OF APPLICATION OF SCREENING CRITERIA

5. REFERENCES ATTACHMENT

SUMMARY

DISPOSITION MATRIX FOR BFN UNITS 1, 2, AND 3 t APPENDICES A.

B.

JUSTIFICATION FOR BFN SPECIFIC RISK SPECIFICATION RELOCATION SIGNIFICANT EVALUATION

BROMNS FERRY NUCLEAR PLANT APPLICATION OF SCREENING CRITERIA INTRODUCTION The purpose of this document is to confirm the results of the BWR Owners Group application of the Technical Specification screening criteria on a plant specific basis for Browns Ferry (BFN) Units 1, 2 5 3. TVA has reviewed the application of the screening criteria to each of the Technical Specifications utilized in BWROG report NED0-31466, "Technical Specification Screening Criteria Application and Risk Assessment,"

(Reference 1) including Supplement 1 (Reference 1), NUREG 1433, Revision 1, Standard Technical Specifications, General Electric Plants BWR/4," and applied the criteria to each of the current BFN Units 1, 2 8 3 Technical Specifications. Additionally, in accordance with the NRC guidance, this confirmation of the application of screening criteria to BFN Units 1, 2, 5 3 includes confirming the risk insights from Probabilistic Risk Assessment (PRA) evaluations, provided in the Reference 1, as applicable to BFN Units 1, 2, E 3.

SCREENING CRITERIA TVA used the screening criteria provided in the NRC Final Policy Statement on Technical Specification Improvements of July 22, 1993 to develop the results contained in the attached matrix. Probabilistic Risk Assessment (PRA) insights as used in the BWROG submittal were used, confirmed by TVA, and are discussed in the next section of this report.

The screening criteria and discussion provided in the NRC Final Policy statement are as follows:

Criterion 1: Installed instrumentation that is used to detect, and indicate in the control room, a significant abnormal degradation of the reactor coolant pressure boundary:

Discussion of Criterion 1: A basic concept in the adequate protection of the public health and safety is the prevention of accidents.

Instrumentation is installed to detect significant abnormal degradation of the reactor coolant pressure boundary so as to allow operator actions to either correct the condition or to shut down the plant safely, thus reducing the likelihood of a loss-of-coolant accident. This criterion is intended to ensure that Technical Specifications control those instruments specifically installed to detect excessive reactor coolant system leakage. This criterion should not, however, be interpreted to include instrumentation to detect precursors to reactor coolant pressure boundary leakage or instrumentation to identify the source of actual leakage (e.g., loose parts monitor, seismic instrumentation, valve position indicators).

Page 1 of 8

BROWNS FERRY NUCLEAR PLANT APPLICATION OF SCREENING CRITERIA Criterion 2: A process variable, design feature, or operating restriction that is an initial condition of a Design Basis Accident (DBA) or transient analyses that either assumes the failure of or presents a challenge to the integrity of a fission product barrier:

Discussion of Criterion 2: Another basic concept in the adequate protection of the public health and safety is that the plant shall be operated within the bounds of the initial conditions assumed in the existing DBA and transient analyses and that the plant will be operated to preclude unanalyzed transients and accidents. These analyses consist of postulated events, analyzed in the FSAR, for which a structure, system, or component must meet specified functional goals. These analyses are contained in Chapters 6 and 15 of the FSAR (or equivalent chapters) and are identified as Condition II, III, or IV events (ANSI N18.2) (or equivalent) that either assume the failure of or present a challenge to the integrity of a fission product barrier.

As used in Criterion 2, process variables are only those parameters for which specific values or ranges of values have been chosen as reference bounds in the DBA or transient analyses and which are monitored and controlled during power operation such that process values remain within the analysis bounds. Process variables captured by Criterion 2 are not, however, limited to only those directly monitored and controlled from the control room. These could also include other features or characteristics that are specifically assumed in DBA or transient analyses if they cannot be directly observed in the control room coefficient hot channel factors).

(e.g.,

moderator temperature and The purpose of this criterion is to capture those process variables that have initial values assumed in the DBA and transient analyses, and which are monitored and controlled during power operation. As long as these variables are maintained within the established values, risk to the public safety is presumed to be acceptably low, This criterion also includes active design features (e.g., high pressure/low pressure system valves and interlocks) needed to preclude unanalyzed accidents and transients.

Criterion 3: A structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a DBA or Transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier:

Discussion of Criterion 3: A third concept in the adequate protection of the public health and safety is that "in the event that a postulated DBA or Transient should occur, structures, systems, and components are available to function or to actuate in order to mitigate the consequences of the DBA or Transient. Safety sequence analyses or their equivalent have been performed in recent years and provide a method of Page 2 of 8

BROWNS FERRY NUCLEAR PLANT APPLICATION OF SCREENING CRITERIA presenting the plant response to an accident. These can be used to define the primary success paths.

A safety sequence analysis is a systematic examination of the actions required to mitigate the consequences of events considered in the plant's DBA and transient analyses, as prese~ted in Chapters 6 and 15 of the plant's FSAR (or equivalent chapters). Such a safety sequence analysis considers all applicable events, whether explicitly or implicitly presented. The primary success path of a safety sequence analysis consists of the combination and sequences of equipment needed to operate (including consideration of the single failure criteria), so that the plant response to DBAs and Transients limits the consequences of these events to within the appropriate acceptance criteria.

It is the intent of this criterion to capture into Technical Specifications only those structures, systems, and components that are part of the primary success path of a safety sequence analysis. Also captured by this criterion are those support and actuation systems that are necessary for items in the primary success path to successfully function. The primary success path for a particular mode of operation does not include backup and diverse equipment (e.g., rod withdrawal block which is a backup to the average power range monitor high flux trip in the startup mode, safety valves which are backup to low temperature overpressure relief valves during cold shutdown).

Criterion 4: A structure, system, or component which operating experience or probabilistic safety assessment has shown to be significant to public health and safety:

Discussion of Criterion 4: It is the Commission's policy that licensees retain in their Technical Specifications LCOs, action statements, and Surveillance Requirements for the following systems (as applicable),

which operating experience and PSA have generally shown to be significant to public health and safety and any other structures, systems, or components that meet this criterion:

~ Reactor Core Isolation Cooling/Isolation Condenser,

~ Residual Heat Removal

~ Standby Liquid Control, and

~ Recirculation Pump Trip.

The Commission recognizes that other structures, systems, or components may meet this criterion. Plant- and design-specific PSA's have yielded valuable insight to unique plant vulnerabilities not fully recognized in the safety analysis report DBA or transient analyses. It is the intent of this criterion that those requirements that PSA or operating experience exposes as significant to public health and safety, consistent with the Commission's Safety Goal and Severe Accident Page 3 of 8

BROWNS FERRY NUCLEAR PLANT APPLICATION OF SCREENING CRITERIA Policies, be retained or included in the Technical Specifications.

The Commission expects that licensees, in preparing their Technical Specification related submittals, will utilize any plant-specific PSA or risk survey and any available literature on risk insights and PSAs.

This material should be employed to strengthen the technical bases for those requirements that remain in Technical Specifications, when applicable, and to verify that none of the requirements to be relocated contain constraints of prime importance in limiting the likelihood or severity of the accident sequences that are commonly found to dominate risk. Similarly, the NRC staff will also employ risk insights and PSAs in evaluating Technical Specifications related submittal. Further, as a part of the Commissions ongoing program of improving Technical Specifications, it will continue to consider methods to make better use of risk and reliability information for defining future generic Technical Specification requirements.

PROBABILISTIC RISK ASSESSMENT INSIGHTS Introduction and Ob'ectives The Final Policy Statement includes a statement that NRC expects licensees to utilize the available literature on risk insights to verify that none of the requirements to be relocated contain constraints of prime importance in limiting the likelihood or severity of the accident sequences that are commonly found to dominate risk.

Those Technical Specifications proposed for relocation to other plant controlled documents will be maintained under the 10 CFR 50.59, safety evaluation review program. These specifications have been compared to a variety of Probabilistic Risk Assessment (PRA) material with two purposes: 1) to identify if a component or variable is addressed by PRA, and 2) to judge if the component or variable is risk-important. In addition, in some cases risk was judged independent of any specific PRA material. The intent of the review was to provide a supplemental screen to the deterministic criteria. Those Technical Specifications proposed to remain part of the Improved Technical Specifications were not reviewed. This review was accomplished in Reference 1 except where discussed in Appendix A, "Justification For Specification Relocation,",

and has been confirmed by TVA for those Specifications to be relocated.

Where Reference 1 did not review a Technical Specification against the criteria of Reference 3, TVA performed a review similar (but not identical) to that described below for Reference 1. The results of these reviews are presented in Appendix B.

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BROWNS FERRY NUCLEAR PLANT APPLICATION OF SCREENING CRITERIA Assum tions and A roach Briefly, the approach used in Reference 1 was the following; The risk assessment analysis evaluated the loss of function of the system or component whose LCO was being considered for relocation and qualitatively assessed the associated effect on core damage frequency and offsite releases. The assessment was based on available- literature on plant risk insights and PRAs. Table 3-1 lists the PRAs used for making the assessments and is provided at the end of this section. A detailed quantitative calculation of the core damage and offsite release effects was not performed. However, the analysis did provide an indication of the relative significance of those LCOs proposed for relocation on the likelihood or severity of the accident sequences that are commonly found to dominate plant safety risks. The following analysis steps were performed for each LCO proposed for relocation:

a ~ List the function(s) affected by removal of the LCO item.

b. Determine the effect of loss of the LCO item on the function(s).

C. Identify compensating provisions, redundancy, and backups related to the loss of the LCO item.

d. Determine the relative frequency (high, medium, and low) of the loss of the function(s) assuming the LCO item is removed from Technical Specifications and controlled by other procedures or programs. Use information from current PRAs and related analyses to establish the relative frequency.

e. Determine the relative significance (high, medium, and low) of the loss of the function(s). Use information from current PRAs and related analyses to establish the relative significance.

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BROWNS FERRY NUCLEAR PLANT APPLICATION OF SCREENING CRITERIA Apply risk category criteria to establish the potential risk significance or non-significance of the LCO item. Risk categories were defined as follows:

RISK CRITERIA Consequence

~Fre uenc Hicih Medium Low High S S NS Medium S S NS Low NS NS NS S = Potential Significant Risk Contributor NS = Risk Non-Significant List any comments or caveats that apply to the above assessment. The output from the above evaluation was a list of LCOs proposed for relocation that could have potential plant safety risk significance if not properly controlled by other procedures or programs. As a result these Specifications will be relocated to other plant controlled documents outside the Technical Specifications.

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BROWNS FERRY NUCLEAR PLANT APPLICATION OF SCREENING CRITERIA TABLE 3-1 BWR PRAs USED IN NEDO-31466 (and Supplement 1)

RISK ASSESSMENT BWR 6 Standard Plant, GESSAR II, 238 Nuclear Island, BWR/5 Standard Plant Probabilistic Risk Assessment, Docket No. STN 50- 447, March 1982.

La Salle Count Station, NED0-31085, Probabilistic Safety Analysis, February 1988.

Grand Gulf Nuclear Station, IDCOR, Technical Report 86.2GG, Verification of IPE for Grand Gulf, March 1987.

Limerick, Docket Nos. 50-352, 50-353, 1981, "Probabilistic Risk Assessment, Limerick Generating Station," Philadelphia Electric Company.

Shoreham, Probabilistic Risk Assessment Shoreham Nuclear Power Station, Long Island Lighting Company, SAI-372-83-PA-01, June 24, 1983.

Peach Bottom 2, NUREG-75/0104, "Reactor Safety Study," WASH-1400, October 1975.

Millstone Point 1, NUREG/CR-3085, "Interim Reliability Evaluation Program: Analysis of the Millstone Point Unit 1 Nuclear Power Plant,"

January 1983.

Grand Gulf, NUREG/CR-1559, "Reactor Safety Study Methodology Applications Program: Grand Gulf Pl BWR Power Plant," October 1981.

NEDC-30935P, "BWR Owners'roup Technical Specification Improvement Methodology (with Demonstration for BWR ECCS Actuation Instrumentation)

Part 2," June 1987.

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BROWNS FERRY NUCLEAR PLANT APPLICATION OF SCREENING CRITERIA RESULTS OF APPLICATION OF SCREENING CRITERIA The screening criteria from Section 2 were applied to the BFN Units 1, 2, and 3 Technical Specifications. The attachment is a summary of that application indicating which Specifications are being retained or relocated. Discussions that document the rationale for the relocation of each Specification which failed to meet the screening criteria are provided in Appendix A. No Significant Hazards Considerations (10 CFR 50.92) evaluations for those Specifications relocated are provided with the Justification for Changes for the specific Technical Specifications.

TVA will relocate those Specifications identified as not satisfying the criteria to licensee controlled documents whose changes are governed by 10 CFR 50.59.

REFERENCES NEDO-31466 (and Supplement 1), "Technical Specification Screening Criteria Application and Risk Assessment," November 1987.

2. NUREG 1433, Revision 1, "Standard Technical Specifications, General Electric Plants BWR/4," April 1995.

3. Final Policy Statement on Technical Specifications Improvements, July 22, 1993, (58FR39132).

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SUMMARY

DISPOSITION MATRIX FOR BFN UNITS I, 2, AND 3 CURRENT TS TITLE BFN STS NUREG RETAINED/ BASIS FOR IHCLUSIOH/EXCLUSION NUNBER ISTS REV. 4 1433 CRITERION NUHBER NUHBER HUHBER FOR INCLUS ION 1.0 Definitions 1.0 Yes Definitions for selected terms used in the Technical Specifications are provided to improve understanding and ensure consistent application. Application of the Technical Specification selection criteria to these definitions is not appropriate. However, definitions for those terms that remain in the Technical Specifications following the application of the selection criteria will be retained.

1/2.1.A Safety Limit: 2.1 2.1.1 2.1 Yes Application of Technical Specification selection criteria to 1/2.1.8 Fuel Cladding Integrity 3.3.1 ' 2.1.2 3.3.1.1 Safety Limits and Limiting Safety System Settings (LSSS) is 1/2.1.C 3.3.5.1 2.1.4 3.3.5.1 not appropriate. The fuel cladding integrity LSSS (with the 3.3.5.2 2.2.1 3.3.5.2 exception of APRH Rod Blocks) are retained by their 3.3.6.1 3.3.2 3.3.6.1 incorporation into the RPS and ECCS instrunentation 3.3.3 Specifications because the associated Functions either 3.3.5 actuate to mitigate consequences of Design Basis Accidents (DBAs) and transients or are retained as directed by the HRC.

2.1.A.1.c Safety Limit: Relocated None None No See Appendix A, page A-4.

Fuel Cladding Integrity -- APRH Rod Block Trip Setting 1/2.2 Safety Limit: 2.1 ~ 2 2.1.3 2.1.2 Yes Application of Technical Specification selection criteria to Reactor Coolant System 3.3.1.1 2.2 3.3.1.1 Safety Limits and Limiting Safety System Settings (LSSS) is Integrity 3.4.3 3.4.2.1 3.4.3 not appropriate. The Reactor Coolant System integrity LSSS 3.3.6.1 3.3.6.1 are retained by incorporation into the RPS and safety relief valve Specifications because the associated components function to mitigate the consequences of events that would result in overpressurization of the RCS.

1.0 ~ C Limiting Condition for LCO 3.0.3 3.0.3 LCO 3.0.3 Yes This Specification provides generic guidance applicable to Operation (LCO) Applicability 3.8.'I 3/4.B.1. 1 3.8.1 one or more Specifications to facilitate understanding of LCOs. As such, direct application of the Technical Specification selection criteria is not appropriate. The general requirements of 1.0.C are retained in the Technical Specifications consistent with NUREG-1433.

SUMMARY

DISPOSITION MATRIX FOR BFN UNITS I, 2, AND 3 CURRENT TS TITLE BFH STS NUREG RETAIHEO/ BASIS FOR INCLUSIOH/EXCLUSIOH NUMBER ISTS REV. 4 1433 CRITERION NUMBER NUMBER NUMBER FOR INCLUSION 1.0.LL Surveillance Requirement (SR) SR 3.0.1 4.0.1 SR 3.0.1 Yes This Specification provides generic guidance applicable to Applicability SR 3.0.2 4.0.2 SR 3.0.2 one or more Specifications to facilitate understanding of SR 3.0.3 4.0.3 SR 3.0.3 SRs. As such, direct application of the Technical Specification selection criteria is not appropriate. The general requirements of 1.0.LL are retained in the Technical Specifications consistent with NUREG-1433.

3/4.1.A Reactor Protection System: 3.3 ~ 1 ~ 1 3/4.3.1 3.3.1.1 Yes - 3, 4 All Functions retained (with exception listed below)

Instrwentation that Initiate a because the various Functions: 1) actuate to mitigate Reactor Scram (Instrwents in consequences of OBAs and/or transients; or, 2) are Table 3.1.1 and associated SRs considered risk significant and retained in accordance with in Table 4.1 ~ 1 and 4.1.2) the NRC Final Policy Statement on Technical Specification Improvements; or, 3) are part of the RPS/Reactor Scram Function; or, 4) provide an anticipatory scram to ensure the scram discharge voiwe and thus RPS remains operable.

Table Turbine First Stage Permissive Relocated None Hone No See RPS Instrwentation Justification for Change (LAS for 3/4.'I.A ISTS 3.3.F 1)-

3/4.1.B Reactor Protection System Power 3.3.8.2 3/4.8.4.4 3.3.8.2 Yes - 3 Provides protection for the RPS bus powered instrwentation Supply against unacceptable voltage and frequency conditions that could degrade instrwentation so that it would not perform the intended safety function.

3/4.2.A Primary Containment and Reactor 3.3.6.1 3/4.3.2 3.3.6.1 Yes - 3, 4 All Functions retained (with exceptions listed below)

Building Isolation: 3.3.6.2 3.3.6.2 because the Functions actuate to mitigate the consequences Instrwentation that initiates 3.3.7.1 3.3.7.1 of a DBA LOCA, Fuel Handling Accident or are considered risk primary contairvrent isolation. significant and are retained in accordance with the NRC (Instrwents in Table 3.2.A and Final Policy Statement on Technical Specification associated SRs in Table 4.2.A) Improvements. The isolation signals generated by the (Exceptions listed below> reactor building isolation instrwentation are implicitly assumed in the safety analyses to initiate closure of valves to limit offsite doses.

3/4.2.A SGTS flow functions Relocated Hone Hone Ho See Secondary Contairment Isolation Instrwentation Justification for Change (LA3 for ISTS 3.3.6.2) 3/4.2.A Reactor Building Isolation Relocated Hone None See Secondary Contalwent Isolation Instrwentation Timer Functions Justification for Change (LA3 for ISTS 3.3.6.2)

SUMMARY

DISPOSITION MATRIX FOR BFN UNITS I, 2, AND 3 CURRENT TS TITLE BFN STS NUREG RETAINED/ BASIS FOR INCLUSION/EXCLUSION NUHBER ISTS REV. 4 1433 CR I TER ION NUMBER NUHBER NUHBER FOR INCLUSION 3/4.2.B Core and Containment Cooling 3.3.5 'I 3/4.3.3 3.3.5.1 Yes - 3, 4 Functions retained (with exceptions listed below) because Systems - Initiation 5 Control: 3.3.5 ' 3/4.3.5 3.3.5.2 the various Functions actuate to mitigate the consequences Instrunentation that initiates 3.3.6.1 3.3.6.1 of 8 DBA LOCA or are considered risk significant and are or controls the core and retained in accordance with the NRC Final Policy Statement containment cooling systems on Technical Specification Improvements.

(LPCI, CS, ADS, NPCI, and RCIC). (Instrunents in Table 3.2.B and associated SRs in Table 4.2.B) (Exceptions listed below)

Table Drywell High Pressure Relocated None None See ECCS Instrunentation Justification for Change (R2 for 3/4.2.B (1<p<2 ~ 5 psig) ISIS 3.3.5.1)

Table Core Spray Sparger to Reactor Relocated None Hone No See Appendix A, Page A-3.

3/4.2.B Pressure Vessel d/p Table Trip System Bus Power Honitors: Relocated None Hone No See Appendix A, Page A-1 3/4.2.B RHR (LPCI), CS, ADS, HPCI, and RCIC Trip Systems Table CS and RHR Discharge Pressure Relocated Hone None No See ECCS Instrunentation Justification for Change (LA3 for 3/4.2.B ISTS 3.3.5.1)

Table End of Cycle Recirculation Pump 3.3.4.1 3/4.3.4.1 3.3.4.1 Yes - 3 EOC-RPT aids the reactor scram in protecting fuel cladding 3/4.2.B Trip: Instrunentation that integrity by ensuring the fuel cladding integrity Safety trips the reactor recirculation Limit is not exceeded during a load rejection or turbine pump to limit the consequences trip transient.

of a failure to scram (ATNS-RPT) ~ (Instruments in Table 3.2.8 and associated SRs in Table 4.2.8))

Table CS and RHR Area Cooler Fan Relocated Hone Hone Ho See ECCS Instrumentation Justification for Change (LA3 for 3/4.2.8 Thermostat ISTS 3.3.5.1) 3/4.2.C Control Rod Block Actuation: 3.3.2.1 3/4.3.6 3.3.2.1 Yes Control Rod Block Actuation Instrunentation functions to Instrunentation that Initiates prevent violation of the HCPR Safety Limit and cladding Control Rod Blocks. plastic strain design limit during a single control rod (Instrunents in Table 3.2.C and withdrawal error event, ensures the initial conditions of associated SRs in Table 4.2.C) the control rod drop accident analysis are not violated, and (Exceptions listed below) prevents inadvertent criticality when the reactor is shutdown (thereby preserving the safety analysis assumptions).

SUHMARY DISPOSITION MATRIX FOR BFN UNITS I, 2, AND 3 CURRENT TS TITLE BFN STS NUREG RETAINED/ BASIS FOR INCLUSION/EXCLUSION NUMBER ISTS REV. 4 1433 CRITERION NUMBER NUMBER NUMBER FOR IHCLUSIOH Table APRM (Upscale Flow Bias, Relocated 3/4.3.6 Hone No See Appendix A, Page A-4.

3/4.2.C Upscale Startup Mode, APRM Downscale, and APRM Inoperative)

Table IRM (Upscale, Downscale, Relocated 3/4.3.6 Hone Ho See Appendix A, Page A-6.

3/4.2.C Detector Not in Startup Position, Inoperative)

Table SRM (Upscale, Downscale, Relocated 3/4 '.6 None See Appendix A, Page A-7.

3/4.2.C Detector Not in Startup Position, Inoperative)

Table Scram Discharge Votune High Relocated 3/4.3.6 Hone No See Appendix A, Page A-B.

3/4.2.C Level 3/4.2.D (Deleted) 3/4.2.E Drywell Leak Detection: 3.4.5 3/4.4.3.1 3.4 6 Yes - 1 Leak detection instrunentation is used to indicate an Instrunentation that monitors abnormal condition of the reactor coolant pressure boundary.

drywell leakage 3/4.2.F Surveillance Instrunentation 3.3.3.1 3/4 3.7.5 3 3 3 1 Yes - 3 Regulatory Guide 1.97 Type A and Category 1 instruoents 3/4 '.M (Post Accident Monitoring retained. See Appendix A. Page A-10, for full discussion of Instrunents): all instrunents in Table 3.2.F.

Instrunentation that provide surveillance information.

(Instrunents in Table 3.2.F and associated SRs in Table 4 '.F) 3/4.2.G Control Room Isolation: 3.3.7.1 3/4.3.7 3.3.7.1 Yes - 3 Functions actuate to maintain control room habitability so Instrunentation that isolates that operation can continue from the control room following the control room and initiates a DBA.

CREVs. (Instrm.nts in Table 3.2.G and associated SRs in Table 4.2.G) 3/4.2.H Flood Protection Relocated Hone Hone Ho See Appendix A, page A-16.

Instrwentation 3/4.2.I Meteorological Monitoring Retocated Hone None No See Appendix A, page A-19.

Instrunentatton 3/4.2.J Seismic Monitoring Relocated None Hone No See Appendix A, page A-18.

Instrwentation

SUMMARY

DISPOSITION MATRIX FOR BFN UNITS I, 2, AND 3 CURRENT TS TITLE BFN STS NUREG RETAINED/ BASIS FOR INCLUSION/EXCLUSION NUHBER ISTS REV. 4 1433 CRITERION NUHBER NUMBER NUHBER FOR INCLUSION 3/4 '.K Explosive Gas Monitoring Relocated None None See Appendix A, page A-21. Part of the program required by Instrunentation BFN Specification 5.5.8.

3/4.2.L ATWS Recirculation Pump Trip 3.3.4.2 3/4.3.4.1 3.3.4.2 Yes - 4 ATWS-RPT is being retained in accordance with NRC Final Policy Statement on I'echnical Specification Improvements due to risk significance.

3/4.3.A.1 Reactivity Hargin - Core 3.1.1 3/4.1.1 3.1.1 Yes - 2 Shutdown Margin (SDH) is assumed as an initial condition for Loading the control rod removal error during a refueling event and the fuel assembly insertion error during a refueling event.

3/4.3.A.2.a Reactivity Hargin - Inoperable 3.1.3 3/4.1.3 ' 3.1.3 Yes-3 Control rods are part of the primary success path for 3/4.3.A.2.b Control Rods 3/4.1.3.5 mitigating the consequences of DBAs and transients.

3/4.3.A.2.c 3/4.1.3.6 3.3.A.2.d 3/4 '.B.1 3.3.A.2.e Scram Accunuiators 3.1.5 3/4.1.3.5 3.1.5 Yes - 3 Same as above.

/4.3.A.2 d 3/4.1.3.7 3/4.3.B.2 Control Rod Housing Support Relocated 3/4.1.3.8 None No See Control Rod Operability Justification for Change (R1 for ISTS 3.1.3) 3/4.3.8.3.b Rod Worth Minimizer 3.3.2.1 3/4.1.4.1 3.3.2.1 Yes - 3 The RWH enforces the Banked Position Withdrawal Sequence (BPWS) to ensure that the initial conditions of the LOCA analysis are not violated.

3/4.3.B.4 Minimum Count Rate for Control 3.3.1.2 3/4.3.7.6 3.3.1.2 Yes Does not satisfy selection criteria, however is being Rod Withdrawal retained because it is considered necessary for flux monitoring during shutdown, startup and refueling operations.

3/4.3.C Scram Insertion Times 3.1.3 3/4.1.3.2 3.1.3 Yes - 3 Control rods are part of the primary success path for 3.1.4 3/4.1.3.3 3.1.4 mitigating the consequences of DBAs and transients. The LOCA 3/4.1.3.4 and transient analyses assune that control rods scram at a specified insertion rate.

3/4.3.D Reactivity Anomalies 3.1.2 3/4.1 ' 3.1.2 Yes - 2 Not a measured process variable, but is important parameter that is used to confirm the acceptability of the accident analysis 3/4.3.F Scram Discharge Volune 3.1.8 3/4.1.3.1 3.1.8 Yes - 3 The capability to insert the control rods ensures the assunptions used for the scram reactivity in the LOCA and transient analyses are maintained. The Scram Discharge Volune (SDV vent and drain valves contribute to the operability of the control rod scram function.

SUMMARY

DISPOSITION MATRIX FOR BFN UNITS I, 2, AND 3 CURRENT TS TITLE BFN STS NUREG RETAIHED/ BASIS FOR INCLUSION/EXCLUSION NUMBER ISTS REV. 4 1433 CRITERION NUMBER NUMBER NUMBER FOR INCI.US ION 3/4.4 Standby Liquid Control System 3.1.7 3/4.1.5 3.1.7 Yes -4 The Standby Liquid Control (SLC) is a backup system to the control rod scram function. This system is being retained per the NRC Final Policy Statement on Technical Specification Improvements due to the risk significance.

,~

-CORE. AHD'CONTAINMEHT COOLING'.:,"

SYSTEMS 3/4.5.A Core Spray System 3.5.1 3/4.5.1 3.5.1 Yes - 3 Core Spray subsystems are part of the ECCS and function to provide cooling water to the reactor core to mitigate large Loss of Coolant Accidents.

3/4.5.8 Residual Heat Removal System 3.5.1 3/4.5.'I 3.5.1 Yes - 3 RHR Low Pressure Coolant Injection subsystems are part of (RHRS) (LPCI AND Contaiment 3.5.2 3/4.5.2 3.5.2 the ECCS and function to provide cooling water to the Cooling) 3.6.2.3 3/4.6.2.2 3.6.2.3 reactor core to mitigate large Loss of Coolant Accidents.

3.6.2.4 3/4.6.2.3 3.6.2.4 RHR Containment Cooling systems provide a reliable source of 3.6.2.5 3.6.2.5 cooling water and functions to provide cooling to the primary contairment under post accident conditions.

3/4.5.B. 11 RHR cross-connect capability None Hone None Relocated See Justification for Change Rl for BFH ISTS 3.5.1, ECCS.

3/4.5.B.12 between units 3/4.5.8.13 3/4.5.C.1 RHR Service Mater and Emergency 3.7.1 3/4.7.1 1~ 3.7.1 Yes - 3 Designed for heat removal from various safety related 3/4.5.C.2 Equipment Cooling Hater Systems 3.7.2 3/4.7.1.2 3.7.2 systems following a DBA. As such, acts to mitigate the 3/4.7.1.3 consequences of an accident.

3/4 '.C.3 Standby Coolant Supply Hone None Hone Relocated See Justification for Change R1 for BFH ISIS 3.7.1, RHRSH.

3/4.5.C.4 Capability 3/4.5.C.5 3/4.5D Equipment Area Coolers Relocated Hone None No Relocated to the Bases as they are part of ECCS Operability.

See ECCS Justification for Changes (3.5.1, LA4) 3/4.5E High Pressure Coolant Injection 3.5.1 3/4.5.1 3.5.1 Yes - 3 The HPCI System is part of the ECCS and functions to System mitigate small break Loss of Coolant Accidents.

3/4.5F Reactor Core Isolation Cooling 3.5.3 3/4.7.4 3.5.3 Yes -4 System retained in accordance with the NRC Final Policy System Statement on Technical Specification improvements due to risk significance.

SUMMARY

DISPOSITION HATRIX FOR BFN UNITS I, 2, AND 3 CURRENT TS TITLE BFN STS NUREG RETAINED/ BASIS FOR INCLUSION/EXCLUSION NUHBER ISTS REV. 4 1433 CRITERION NUHBER NUHBER NUHBER FOR INCLUSION 3/4 ~ 5G Automatic Depressurization 3.5.1 3/4.5.1 3.5.1 Yes - 3 The ADS is part of the ECCS and is designed to mitigate a System (ADS) small or mediun break Loss of Coolant Accident. The ADS acts to rapidly reduce reactor vessel pressure in a LOCA situation in which the HPCI System fails to automaticaily maintain reactor vessel water level. This depressurization enables the low-pressure emergency core cooling systems to deliver cooling water to the reactor core.

3/4.5H Haintenance of Filled Discharge 3.5.1 3/4.5.1 3 ~ 5.1 Yes - 3, 4 This Specification ensures the operability of the ECCS and Pipe 3.5.2 3/4.5.2 3 '.2 RCIC System, which function to mitigate the consequences of 3.5.3 3/4.5.4 3.5.3 a LOCA (ECCS) or is required to be retained by the NRC Final Policy Statement on Technical Specification Isprovements (RCIC).

3/4.51 Average Planar Linear Heat 3.2.1 3/4.2.1 3.2.1 Yes - 2 The APLHGR limit is an initial condition in the safety Generation Rate (HAPLHGR) analyses.

3/4.5J Linear Heat Generation Rate 3.2.3 3/4.2.4 3.2.3 Yes - 2 The LHGR limit is an initial condition in the safety (LHGR) analyses.

3/4.5K Hinimm Critical Power Ratio 3.2.2 3/4.2.3 3.2 ' Yes - 2 The HCPR limit is an initial condition in the safety (HCPR) analyses.

3/4.5L APRH Setpoints 3.2.4 3/4.2.2 3.2.4 Yes - 2, 3 The Operability of the APRHs and their setpoints is an initial condition of all safety analyses that assune rod insertion upon reactor scram.

3/4.5H Core Thermal-Hydraulic 3.4.1 3/4.4.1.1 3.4.1 Yes-2 Recirculation loop flow is an initial condition in the Stability 3/4.4.1.3 safety analysis.

3/4.6.A.1 Thermal and Pressurization 3 '.9 3/4.4.6.1 3.4.'IO Yes - 2 Establishes initial conditions such that operation is 3/4.6.A.2 Limitations prohibited in areas or at temperature rate changes that 3/4.6.A.3 might cause undetected flaws to propagate in turn 3/4.6.A.4 challenging the reactor coolant pressure boundary integrity.

3/3.6.A.S 3/4.6.A.6 Idle Recirculation Loop Startup 3.4.9 3/4.4.6.1 3.4.10 Yes - 2 Same as above.

3/4.6.A.7 3/4.6.8.1 Coolant Chemistry Relocated 3/4.4.4 Hone No See Appendix A, Page A-12.

3/4.6.8.2 3/4.6.8.3 3/4.6.8.4 3/4.6.8.5

SUMMARY

DISPOSITION MATRIX FOR BFN UNITS I, 2, AND 3 CURRENT TS TITLE BFN STS NUREG RETAINED/ BASIS FOR INCLUSION/EXCLUSION NUMBER ISTS REV. 4 1433 CRITERION NUMBER NUHBER NUMBER FOR IHCLUSION 3/4.6.B.6 Specific Activity 3.4.6 3/4.4.5 3.4.7 Yes - 2 The specific activity in the reactor coolant is an initial condition for evaluation of the consequences of an accident due to a main steam line break (MSLB) outside contaiwent.

3/4.6.C.1 Coolant Leakage 3.4.4 3/4.4.3.1 3.4.4 Yes-1,2 Leakage beyond limits would indicate an abnormal condition of the reactor coolant pressure boundary. Operation in this condition may result in reactor coolant pressure boundary failure. Leakage detection instrunents are used to indicate an abnormal condition of the reactor coolant pressure boundary.

3/4.6.C.2 Leakage Detection Systems 3.4.5 3/4.4.3.2 3.4.6 Yes-1, 2 Same as above.

3/4.6.D Relief Valves 3.4.3 3/4.4.2.1 3.4.3 Yes - 3 The Safety and Relief Valves are assuned to operate to maintain the reactor pressure below design limits.

3/4.6E Jet Pumps 3.4.2 3/4.4.1.2 3.4.2 Yes - 2 Jet Purp operability is explicitly assed in the design basis LOCA to assure adequate core reflood capability.

3/4.6F Recirculation Pump Operation 3.4.1 3/4.4.1.1 3.4.1 Yes - 2 Recirculation loop flow is an initial condition in the 3/4.4.1.3 safety analysis.

3/4.6G Structural Integrity Relocated 3/4.4.8 None See Appendix A, Page A-13 3/4 'H Snubbers Relocated 3/4.7.5 None Ho See Justification for Change (CTS 3.6.H/4.6.H, LA1) for relocating snubbers in CTS 3.6.H/4.6.H. (Spec 3.4 markup) 3/4.7.A. 1 Suppression Chamber 3.6.2.1 3/4.6.2.1 3.6.2 ' Yes - 2, 3 The suppression pool water voiune and terrperature are 3.6.2.2 3.6.2.2 initial conditions in the DBA LOCA contairvaent response analysis and mitigate the consequences of a DBA.

3/4.7.A.2 Primary Contairvaent Integrity 3.6.1.1 3/4.6.1.1 3.6.1.1 Yes - 3 Primary contairvaent functions to mitigate the consequences 3.6.1.2 3/4.6.1 ' 3.6.1.2 of a DBA. Primary contaiment leakage is an assumption 3.6.1.3 3/4.6.1.3 3.6.1.3 utilized in the LOCA safety analysis to ensure primary 3/4.6.1 ' contairment operability.

3/4.7.A.3 Pressure Suppression Chamber- 3.6.1.5 3/4.6.4.2 3.6.1.7 Yes - 3 Pressure suppression chamber to reactor building vacrxmr Reactor Building Vacuun breaker operation is relied upon to limit a negative Breakers pressure differential, secondary to primary contairvaent, that could challenge primary contairment integrity.

3/4.7.A.4 Drywell-pressure Suppression 3.6.1.6 3/4.6.4.1 3.6.1.8 Yes-3 Drywell-pressure suppression chamber vacrxmr breaker Chamber Vacua Breakers operation is assumed in the LOCA analysis to limit drywell pressure thereby ensuring primary contairment integrity.

SUMMARY

DISPOSITION MATRIX FOR BFN UNITS I, 2, AND 3 CURRENT TS BFN STS NUREG RETAINED/ BASIS FOR INCLUSION/EXCLUSIOH NUMBER ISTS REV. 4 1433 CR I TER ION NUMBER NUMBER NUMBER FOR IN CLUB I ON 3/4.7.A.S Oxygen Concentration 3.6.3.2 3/4.6.6.4 3.6.3.2 Yes - 2 Oxygen concentration is limited such that, when combined with hydrogen (that is postulated to evolve following a LOCA), the total explosive gas concentration remains below explosive levels. Therefore, primary contairvnent integrity is maintained.

3/4.7.A.6 Drywell-suppression Chamber 3.6.2.6 3/4.6.2.4 3.6.2.5 Yes - 2 Dryweii-suppression Chamber Differential Pressure is an Differential Pressure initial condition in the DBA LOCA contairment response analysis.

3/4.78 Standby Gas Treatment System 3.6.4 ' 3/4.6.5.3 3.6.4.3 Yes - 3 System functions following a DBA to limit offsite releases.

3/4.7C Secondary Contaireent 3.6.4.1 3/4.6.5.1 3.6.4.1 Yes - 3 Secondary contaiment integrity is relied on to limit the 3.6.4.2 3/4.6.5.2 3.6.4.2 offsite dose during an accident by ensuring a release to contairment is delayed and treated prior to release to the enviroreent. Damper operation within time limits establishes secondary contaim.nt and limits offsite releases to acceptable values.

3/4.7D Primary Contairment Isolation 3.6.1.3 3/4.6.3 3.6.1.3 Yes - 3 Isolation valves function to limit DBA consequences.

3.7.F.3.a Valves 3/4.6.1.8 3/4.7F Primary Contairment Purge Relocated Hone None No See Justification for Change (CTS 3.7.F/4.7.F, R1 at the end System of markup for proposed BFH ISTS 3.6) for relocating primary contairment purge system.

3/4.7E Control Room Emergency 3.7.3 3/4.7.2 3.7.4 Yes - 3 Maintains habitability of the control room so that operators Ventilation can remain in the control room following an-accident. As such, it mitigates the consequences of an accident by allowing the operators to continue accident mitigat'Ion activities from the control room.

3/4.7.G Contairment Atmosphere Dilution 3.6.3 ~ 1 3/4.6.6.2 3.6.3.4 Yes - 3 System ensures oxygen concentration is maintained below the System (CAD) explosive level following a LOCA by inerting the dryweli with nitrogen. Therefore, contairment integrity is maintained.

3.8.A.S Liquid Holdup Tanks 5.5.8 Hone 5.5.8 Yes Although this Specification does not meet any criteria of 3/4.8.A.6 the HRC Final Policy Statement, it has been retained in accordance with NRC Letter from II. T. Russell to the Industry ITS chairpersons, dated October 25, 1993.

SUMMARY

DISPOSITION MATRIX FOR BFN UNITS I, 2, AND 3 CURRENT TS TITLE BFH STS HUREG RETAINED/ BASIS FOR INCLUSION/EXCLUSION NUMBER ISTS REV. 4 1433 CRITERION NUMBER NUMBER NUMBER FOR I NCLUS IOH 3.8.8.9 Airborne Effluents - Explosive 5.5.8 None 5.5.8 Yes See Appendix A, page A-20. This is a requirement of the 3.8.B.10 Gas Mixture program required by BFN Specification 5.5.8.

4.8.8.5 3/4.8.E Miscellaneous Radioactive Relocated 3/4.7.6 None No See Appendix A, page A-'I7.

Materials Sources 3/4.9.A.1 Auxiliary Electrical Equipment 3.8.1 3/4.8.1.1 3.8.1 Yes -3 The operability of the AC power sources is part of the 3.9.A.2 - A. C. Sources Operating primary success path of the accident analyses.

3.9.A.6 3/4.9.8.1 3/4.9.8.3 3.9.8.15 3.9.A.3 Auxiliary Electrical Equipment 3.8.7 3/4.8.3.1 3.8.9 Yes - 3 The operability of the distribution system is part of the

/4.9.A.4.D - Buses and Boards Available primary success path of the accident analyses.

4.9.A.S 3/4.9.8.2 3/4.9.B.4 3/4.9.8.5 3/4.9.B.6 3.9.8.12 3.9.8.13 3.9.B.14 3.9.B.15 3.9.A.4 D. C. Power System 3.8.4 3/4.8.3.1 3.8.4 Yes -3 The operability of the DC subsystems is consistent with the

/4.9.A.2 initial assumptions of the accident analyses.

3.9.8.7 3.9.8.8 3.9.B.15 3.9.A.5 Logic Systems 3.8.1 3/4.8.1.1 3.8.1 Yes - 3 Required to mitigate the consequences of a DBA.

/4.9.A.3.a 3.3.5.1 3.3.5.1 3/4.9.C.1 A. C. Sources - Operation in 3.8.2 3/4.8.1.2 3.8.2 Yes - 3 Same as above.

3.9.C.2 Cold Shutdown 3.9.C.3 Onsite Electrical Power 3.8.8 3/4.8.1.2 3.8.10 Yes - 3 Same as above.

3.9.C.4 Distribution - Shutdown 3/4.9.D Unit 3 Diesel Generators 3.8.1 3/4.8.1.1 3.8.1 Yes - 3 Same as above.

Required for Unit 2 Operation 3.8.2 3/4.8.1.2 3.8.2 10

SUMMARY

DISPOSITION MATRIX FOR BFN UNITS I, 2, AND 3 CURRENT TS TITLE BFH STS NUREG RETAINED/ BASIS FOR INCLUSION/EXCLUSION NUMBER ISTS REV. 4 1433 CR I TER IOH NUMBER NUMBER NUHBER FOR INCLUSION 3/4.10.A.1 Refueling Operations- 3.9.1 3/4.9.'I 3.9.1 Yes - 3 The refueling interlocks protect against prompt reactivity 3/4.10.A.2 Interlocks 3.9.2 3.9.2 excursions during the Refuel Hode. The safety analyses for 3.9.3 3.9.3 the control rod removal error during refueling end the fuel assembly insertion error during refueling assme the functioning of the refueling interlocks.

3.10.A.3 Refueling Platform Equipment Relocated 3/4.9.7 None No See Appendix A, Page A-22.

3.'IO.A.4 Interlocks 3/4.10.A.5 Refueling Operations - Single 3.10.4 3/4.9.10 ~ 3.10.4 Yes This requirement is being retained to allow relaxation of Control Rod Naintenance 2 certain Limiting Conditions for operation (LCOs) under specific conditions to allow testing and maintenance. This requirement is directly related to several LCOS. Direct application of the Technical Specification selection criteria is not appropriate. However, this requirement, directly tied to LCOs that remain in Technical Specifications, will also remain in Technical Specifications.

3/4.10.A.6 Refueling Operations - Removal 3.10.5 3/4.9.10. 3.10.4 Yes Same as above.

of Two Control Rods 2 3/4.10.A.7 Refueling Operations - Removal 3.10.6 3/4.9.10 ' 3.10.6 Yes Same as above.

of Any Number of Control Rods 3/4.10. B Refueling Operations - Core 3.3.1.2 3/4.9.2 3.3.1.2 Yes Does not satisfy criteria for inclusion but is retained Monitoring because it is considered necessary for flux monitoring during shutdown, startup, and refueling operations.

3/4.10.D Refueling Operations - Reactor Relocated 3/4.9.6 None No See Appendix A, Page A-14 Building Crane 3/4.10.E Refueling Operations - Spent Relocated 3/4.9.6 None See Appendix A, Page A-15 3.10 ' Fuel Cask 5.0 Major Design Features 4.0 5.0 4.0 Yes Application of Technical Specification selection criteria is not appropriate. However, Design Features will be included in Technical Specifications as required by 10 CFR 50.36a.

6.0 Administrative Controls 5.0 6.0 5.0 Yes Application of Technical Specification selection criteria is not appropriate. However, Administrative Controls will be included in Technical Specifications as required by 10 CFR 50.36a.

11

APPENDIX A JUSTIFICATION FOR SPECIFICATION RELOCATION

APPENDIX A TABLE 3/4.2.B TRIP SYSTEM BUS POWER MONITORS FOR THE RHR (LPCI), CORE SPRAY, ADS, HPCI AND RCIC TRIP SYSTEMS LCO Statement:

The limiting conditions for operation for the instrumentation that initiates or controls the core and containment cooling systems are given in Table 3.2.B.

Table 3.2.B Instrumentation that Initiates or Controls the Core and Containment Coolin S stems 3/4.2-17 RHR (LPCI) Trip System Bus Power Monitor 3/4.2-17 Core Spray Trip System Bus Power Monitor 3/4.2-17 -ADS Trip System Bus Power Monitor 3/4.2-18 HPCI Trip System Bus Power Monitor 3/4.2-18 RCIC Trip System Bus Power Monitor Discussion:

The Trip System Bus Power Monitors for the RHR (LPCI), Core Spray, ADS, HPCI and RCIC trip systems alarm if a fault is detected in the power system to the appropriate systems logic. No design basis accident (DBA) or transient analyses takes credit for the Trip System Bus Power Monitors. This instrumentation provides a monitoring/alarm function only.

Com arison to Screenin Criteria:

The Trip System Bus Power Monitors are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

2. The Trip System Bus Power Monitors are not process variables that are initial conditions of a DBA or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. The Trip System Bus Power Monitors are not part of the primary success path that functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

As discussed in Sections 3.5 and 6 of NEDO-31466 and summarized in Table 4-1 (item 106) of NED0-31466, Supplement 1, and verified by TVA, the loss of the RHR (LPCI), Core Spray, ADS, HPCI and RCIC Trip System Bus Power Monitors was found to be a non-significant risk contributor to core damage frequency and offsite releases.

A-1

APPENDIX A TABLE 3/4.2.B TRIP SYSTEM BUS POWER MONITORS FOR THE RHR (LPCI), CORE SPRAY, ADS, HPCI AND RCIC TRIP SYSTEMS (cont'd.)

==

Conclusion:==

Since the screening criteria have not been satisfied, the RHR (LPCI), Core Spray, ADS, HPCI and RCIC Trip System Bus Power Monitors LCO and Surveillances may be relocated to a licensee controlled document.

A-2

APPENDIX A TABLE 3/4.2.8 CORE SPRAY SPARGER TO REACTOR PRESSURE VESSEL d/p LCO Statement:

The limiting conditions for operation for the instrumentation that initiates or controls the core and containment cooling systems are given in Table 3.2.B.

Table 3.2.B Instrumentation that Initiates or Controls the Core and Containment Coolin S stems 3/4.2-17 Core Spray Sparger to Reactor Pressure Vessel d/p Discussion:

This instrumentation measures the differential pressure between the core spray sparger and the reactor pressure vessel above the core plate and alarms if a break is detected. This Function does not actuate any equipment; it provides an alarm function only. This Function monitors the integrity of the core spray system piping in the reactor annulus region which would not otherwise be apparent to the operators. It is not credited in the accident analysis.

Com arison to Screenin Criteria:

This instrumentation is not the primary method for detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

2. This instrumentation is not a process variable that is an initial condition of a DBA or transient analysis that either, assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. This instrumentation is not part of the primary success path that functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

As discussed in Appendix B, Page 1, TVA found the loss of the Core Spray Sparger to Reactor Pressure Vessel d/p Instrumentation to be a non-significant risk contributor to core damage frequency and offsite releases.

r

==

Conclusion:==

Since the screening criteria have not been satisfied, the Core Spray Sparger to Reactor Pressure Vessel d/p Instrumentation LCO and Surveillances may be relocated to a licensee controlled document.

A-3

APPENDIX A 2.1.A.l.c APRH ROD BLOCK TRIP SETTING TABLE 3/4.2.C CONTROL ROD BLOCKS - APRH UPSCALE (FLOW BIASED, STARTUP MODE), APRH DOWNSCALE LSSS Statement:

The limiting safety system settings shall be as specified below:

A.l.c The APRH Rod Block Trip Setting shall be less than or equal to the limit specified in the COLR LCO Statement:

The limiting conditions of operation for the instrumentation that initiates control rod blocks are given in Table 3.2.C.

Table 3.2.C Instrumentation that Initiates or Controls the Core and Containment Coolin S stems 3/4.2-25 APRH Upscale (Flow Biased) 3/4.2-25 APRM Upscale (Startup Mode) 3/4.2-25 APRM Downscale 3/4.2-25 APRM Inoperative Discussion:

The Average Power Range Monitor (APRM) control rod blocks function to prevent a control rod withdrawal error during power range operations using LPRH signals to create the APRH rod block signal. APRHs provide information about the average core power and APRH rod blocks are not assumed to mitigate a DBA or transient.

Com arison to Screenin Criteria:

The APRH control rod blocks are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

2. The APRH control rod block instrumentation is not used to monitor a process variable that is an initial condition of a DBA or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. The APRH control rod blocks are not part of the primary success path that functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

A-4

APPENDIX A 2.1.A.l.c APRH ROD BLOCK TRIP SETTING TABLE 3/4.2.C CONTROL ROD BLOCKS - APR. UPSCALE (FLOW BIASED, STARTUP MODE), APRH DOWNSCALE (cont'd.)

As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 135) of NEDO 31466, and verified by TVA, the loss of the APRH control rod block functions was found to be a non-significant risk contributor to core damage frequency and offsite releases.

==

Conclusion:==

Since the screening criteria have not been satisfied, the APRH Control Rod Block Instrumentation LCO and Surveillances may be relocated to a licensee controlled document.

A-5

APPENDIX A TABLE 3/4.2.C CONTROL ROD BLOCKS - IRH UPSCALE, IRH DOWNSCALE, IRH DETECTOR NOT IN STARTUP POSITION, IRH INOPERATIVE LCO Statement:

The limiting conditions of operation for the instrumentation that initiate control rod blocks are given in Table 3.2.C.

Table 3.2.C Instrumentation that Initiates or Controls the Core and Containment Coolin S stems 3/4.2-25 IRH Upscale 3/4.2-25 IRH Downscale 3/4.2-25 IRH Detector Not In Startup Position 3/4.2-25 IRH Inoperative Discussion:

The Intermediate Range Monitor (IRH) control rod blocks function to prevent a control rod withdrawal error during reactor startup using IRH signals to create the rod block signal. IRHs are provided to monitor the neutron flux levels during refueling and startup conditions. No design basis accident or transient analysis takes credit for rod block signals initiated by IRHs.

Com arison to Screenin Criteria:

1. The IRH control rod blocks are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

2. The IRH control rod block instrumentation is not a process variable that is an initial condition of a DBA or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. The IRH control rod blocks are not part of the primary success path that functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 138) of NED0-31466, and verified by TVA, the loss of the IRH control rod block functions was found to be a non-significant risk contributor to core damage frequency and offsite releases.

t

Conclusion:

Since the screening criteria have not been satisfied, the IRH Control Rod Block Instrumentation LCO and Surveillances may be relocated to a licensee controlled document.

A-6

APPENDIX A TABLE 3/4.2.C CONTROL ROD BLOCKS - SRM UPSCALE, SRM DOWNSCALE, SRH DETECTOR NOT IN STARTUP POSITION, SRM INOPERATIVE LCO Statement:

The limiting conditions of operation for the instrumentation that initiates control rod blocks are given in Table 3.2.C.

Table 3.2.C Instrumentation that Initiates or Controls the Core and Containment Coolin S stems 3/4.2-25 SRH Upscale 3/4.2-25 SRM Downscale 3/4.2-25 SRM Detector Not In Startup Position 3/4.2-25 SRM Inoperative Discussion:

The Source Range Monitor (SRM) control rod blocks function to prevent a control rod withdrawal error during reactor startup using SRM signals to create the rod block signal. SRH signals are used to monitor the neutron flux levels during refueling, shutdown, and startup conditions. No design basis accident or transient analysis takes credit for rod block signals initiated by the SRMs.

Com arison to Screenin Criteria:

1. The SRM control rod blocks are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

2. The SRH control rod block instrumentation is not a process variable that is an initial condition of a DBA or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. The SRM control rod blocks are not part of the primary success path that functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 137) of NED0-31466, and verified by TVA, the loss of the SRM control rod block functions was found to be a non-significant risk contributor to core damage frequency and offsite releases.

t

Conclusion:

Since the screening criteria have not been satisfied, the SRH Control Rod Block Instrumentation LCO and Surveillances may be relocated to a licensee controlled document.

A-7

APPENDIX A TABLE 3.2.C CONTROL ROD BLOCKS - SCRAM DISCHARGE INSTRUMENT VOLUME HIGH LEVEL LCO Statement:

The limiting conditions for operation for the instrumentation that initiates control rod blocks are given in Table 3.2.C.

Table 3.2.C Instrumentation that Initiate Control Rod Blocks 3/4.2-25 Scram Discharge Instrument Volume High Level Discussion:

The Scram Discharge Volume (SDV) control rod block functions to prevent control rod withdrawals during power range operations, utilizing SDV high level signals to create the rod block signal, if water is accumulating in the SDV. The purpose of monitoring the SDV water level is to ensure that there is sufficient volume remaining to contain the water discharged by the control rod drive during a scram, thus ensuring that the control rods will be able to insert fully. This rod block signal provides an indication to the operator that water is accumulating in the SDV and prevents further control rod withdrawals. With continued water accumulation, a reactor protection system initiated scram signal will occur. Thus, the SDV water level rod block signal provides an opportunity for the operator to take action to avoid a subsequent scram. No design basis accident (DBA) or transient analysis takes credit. for rod block signals initiated by the SDV high level instrumentation.

Com arison to Screenin Criteria:

The SDV control rod block is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

2. The SDV control rod block instrumentation is not a process variable that is an initial condition of a DBA or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. The SDV control rod block is not part of the primary success path that functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

4. As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 139) of NED0-31466, and verified by TVA, the loss of the Scram Discharge Volume High Level Control Rod Block Instrumentation was found to be a nonsignificant risk contributor to core damage frequency and offsite releases.

A-8

APPENDIX A TABLE 3.2.C CONTROL ROD BLOCKS - SCRAM DISCHARGE INSTRUMENT VOLUME HIGH LEVEL (cont'd.)

==

Conclusion:==

Since the screening criteria have not been satisfied, the Scram Discharge Instrument Volume High Level Control Rod Block Instrumentation LCO and Surveillances may be relocated to a licensee controlled document.

A-9

APPENDIX A 3/4. 2. F SURVEILLANCE INSTRUHENTATION LCO Statement:

The limiting conditions for the instrumentation that provides surveillance information readouts are given in Table 3.2.F Table 3.2.F Surveillance Instrumentation 3/4.2-31 Reactor Water Level 3/4.2-31 Reactor Pressure 3/4.2-31 Drywell Pressure 3/4.2-31 Drywell Air Temperature 3/4.2-31 Suppression Chamber Air Temperature 3/4.2-31 Control Rod Position 3/4.2-31 Neutron Honitoring 3/4.2-31 Drywell Pressure Alarm 3/4.2-31 Drywell Temperature and Pressure and Timer 3/4.2-31 CAD Tank Level 3/4.2-32 Drywell and Torus Hydrogen Concentration 3/4.2-32 Drywell to Suppression Chamber Differential Pressure 3/4.2-32 Relief Valve Tailpipe Thermocouple Temperature or Acoustic Honitor on Relief Valve Tailpipe 3/4.2-32 Primary Containment High Range Radiation Honitors 3/4.2-32 Drywell Pressure - Wide Range 3/4.2-32 Suppression Chamber Water Level - Wide Range 3/4.2-32 Suppression Pool Bulk Temperature 3/4.2-32 Wide Range Gaseous Effluent Radiation Honitor Discussion:

Each individual accident monitoring parameter has a specific purpose, however, the general purpose for all accident monitoring instrumentation is to provide sufficient information to confirm an accident is proceeding per prediction, i.e., automatic safety systems are performing properly, and deviations from expected accident course are minimal.

Com arison to Screenin Criteria:

The NRC position on application of the deterministic screening criteria to post-accident monitoring instrumentation is documented in letter dated Hay 7, 1988 from T. E. Hurley (NRC) to R. F. Janecek (BWROG). The position taken was that the post-accident monitoring instrumentation table list should contain, on a plant specific basis, all Regulatory Guide 1.97 Type A instruments specified in the plants SER on Regulatory Guide 1.97, and all Regulatory Guide 1.97 Category 1 instruments. Accordingly, this position has been applied to the BFN Regulatory Guide 1.97 instruments. Those instruments not meeting this criteria have been relocated from the Technical Specifications to a licensee controlled document.

APPENDIX A 3/3.2.F SURVEILLANCE INSTRUMENTATION (cont'd.)

The following summarizes the BFN position for those instruments currently in Technical Specifications.

From NRC SER dated April 30, 1984,

Subject:

Conformance to RG 1.97 Cate or 1 or T e A Variables

1. Reactor Pressure

2. Reactor Vessel Water Level (wide range, accident range)

3. Suppression Pool Water Temperature Suppression Pool Water Level (wide range)

5. Drywell Pressure (normal range, wide range)

6. Drywell Air Temperature

7. Primary Containment Area Radiation

8. Drywell and Torus Hydrogen Concentration For other post-accident monitoring instrumentation currently in Technical Specifications, their loss is not considered risk significant since the variable they monitored did not qualify as a Type A (one that is important to safety and needed by the operator, so that the operator can perform necessary manual actions) or Category 1 variable .

==

Conclusion:==

Since the screening criteria have not been satisfied for instruments that do not meet Regulatory Guide 1.97 Type A variable requirements or Category 1 variable Type A instruments, their associated LCO and Surveillances will be relocated to a licensee controlled document. The instruments to be relocated are as follows:

l. Drywell Temperature and Pressure Timer

2. Suppression Chamber Air Temperature

3. Control Rod Position 4, Neutron Monitoring

5. Drywell Pressure Alarm

6. CAD Tank Level

7. Drywell to Suppression Chamber Differential Pressure

8. Relief Valve Tailpipe Thermocouple Temperature or Acoustic Monitor on Relief Valve Tailpipe

9. Wide Range Gaseous Effluent Radiation Monitor

APPENDIX A 3/4.6.B.1 - 5 PRIMARY SYSTEM BOUNDARY - COOLANT CHEMISTRY LCO Statement:

The following limits shall be observed for reactor water quality prior to any startup and when operating at rated pressure:

a) Conductivity at 25'C - 2.0 mho/cm b) Chloride concentration - 0. 1 ppm Discussion:

Poor reactor coolant water chemistry contributes to the long-term degradation of system materials and, thus, is not of immediate importance to the plant operator. Reactor coolant water chemistry is maintained to reduce the possibility of failure in the reactor coolant system pressure boundary caused by corrosion. In summary, the chemistry monitoring activity is of a long term preventive purpose rather than mitigative.

Com arison to Screenin Criteria:

1. Reactor coolant water chemistry is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

2. Reactor coolant water chemistry is not a process variable that is an initial condition of a DBA or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. Reactor coolant water chemistry is not part of the primary success path that functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 211) of NED0-31466, and verified by TVA, Coolant Chemistry requirements not being met was found to be a non-significant risk contributor to core damage frequency and offsite releases.

==

Conclusion:==

Since the screening criteria have not been satisfied, the Coolant Chemistry (Conductivity and Chloride) LCO and Surveillances may be relocated to a licensee controlled document.

APPENDIX A 3/4.6.G PRIMARY SYSTEM BOUNDARY - STRUCTURAL INTEGRITY LCO Statement:

The structural integrity of the primary system boundary shall be maintained at the level required by the original acceptance standards throughout the life of the station.

Discussion:

The inspection programs for ASHE Code Class 1, 2, and 3 components ensure that the structural integrity of those components will be maintained throughout the components life. Operability of the primary system boundary is ensured by separate Technical Specifications and therefore, the inspections are not required to be retained in the Technical Specifications. This Technical Specification is more directed toward prevention of component degradation and continued long term maintenance of acceptable structural conditions. However, it is not necessary to retain this Specification to ensure the operability of the primary system boundary.

Com arison to Screenin Criteria:

1. The inspections stipulated by this Specification are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

2. The inspections stipulated by this Specification do not monitor process variables that are initial conditions of a DBA or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. The ASNE Code Class 1, 2, and 3 components inspected per this Specification are assumed to function to mitigate a DBA. Their capability to perform this function is addressed by other Technical Specifications. This Technical Specification, however, only specifies inspection requirements for these components; and these inspections can only be performed when the plant is shutdown. Therefore, Criterion 3 is not satisfied.

4, As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 216) of NED0-31466, and verified by TVA, the lack of a Structural Integrity Specification was found to be a non-significant risk contributor to core damage frequency and offsite releases since the requirement is currently covered by 10 CFR 50.55a and the Inservice Inspection Program.

==

Conclusion:==

Since the screening criteria have not been satisfied, the Structural Integrity LCO and Surveillance may be relocated to a licensee controlled document.

A-13

APPENDIX A 3/4.10.D REFUELING OPERATIONS - REACTOR BUILDING CRANE LCO Statement The reactor building crane shall be OPERABLE:

a. When a spent fuel cask is handled.

b. Whenever new or spent fuel is handled with the 5-ton hoist.

Discussion:

The reactor building crane and 125 ton hoist are required to be operable for handling of the spent fuel in the reactor building. This LCO specifies minimum operability requirements to prevent damage to the refueling platform equipment and core internals. The crane is not assumed to function to mitigate the consequences of a DBA.

Com arison to Screenin Criteria:

1. The reactor building crane is not used, nor is it capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary (RCPB).

2. The reactor building crane is not a process variable that is an initial condition of a DBA or transient analyses that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. The reactor building crane is not a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

4. As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 287) of NED0-31466, and verified by TVA, Reactor building crane requirements not being met was found to be a non-significant risk contributor to core damage frequency and offsite releases.

==

Conclusion:==

Since the screening criteria have not been satisfied, the LCO and associated surveillance may be relocated to the Technical Requirements Manual.

A-14

APPENDIX A 3/4.10.E REFUELING OPERATIONS - SPENT FUEL CRANE 3.10.F LCO Statements Spent Fuel Cask Upon receipt, an empty fuel cask shall not be lifted until a visual inspection is made of the cask-lifting trunnions and fastening connection has been conducted.

Spent Fuel Cask Handling - Refueling Floor Administrative control shall be exercised to limit the height the spent fuel cask is raised above the refueling floor by the reactor building crane to 6 inches, except for entry into the cask decontamination chamber where height above the floor will be approximately 3 feet.

The spent fuel cask yoke safety links shall be properly positioned at all times except when the cask is in the decontamination chamber.

Discussion:

BFN analysis has been performed to address the handling of spent fuel cask.

However, BFN currently does not have the need to handle spent fuel cask.

Therefore, these LCOs serve no useful purpose and should be deleted.

Com arison to Screenin Criteria:

The Spent fuel cask and spent fuel cask handling controls are not used to detect, and indicate in the control room a significant abnormal degradation of the reactor coolant pressure boundary (RCPB).

2. The Spent fuel cask and spent fuel cask handling controls are not capable of monitoring a process variable that is an initial condition of a DBA or transient analyses that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. The Spent fuel cask and spent fuel cask handling controls are not a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 287) of NED0-31466, and verified by TVA, Spent fuel cask and spent fuel cask handling control requirements not being met 'was found to be a non-significant risk contributor to core damage frequency and offsite releases.

APPENDIX A 3/4.10.E REFUELING OPERATIONS - SPENT FUEL CRANE 3.10.F (cont'd.)

==

Conclusion:==

Since the screening criteria have not been satisfied and the LCOs serve no useful purpose, the LCOs and associated surveillance may be deleted.

A-16

APPENDIX A 3/4.2.H FLOOD PROTECTION INSTRUMENTATION LCO Statement:

The unit shall be shutdown and placed in the cold condition when Wheeler Reservoir lake stage rises to a level such that water from the reservoir begins to run across the pumping station deck at elevation 565. Requirements for the instrumentation that monitors the reservoir level are given in Table 3.2.H.

Discussion:

Provides capability to predict flood levels of large magnitudes which allows the plant to take advantage of advance warning to take appropriate action when reservoir levels above normal pool are predicted.

Com arison to Screenin Criteria:

1. The Reservoir Level Monitoring instrumentation is not used to detect, t

and indicate in the control room a significant abnormal degradation of the reactor coolant pressure boundary (RCPB).

2. The Reservoir Level Monitoring instrumentation is not capable of monitoring a process variable that is an initial condition of a DBA or transient analyses that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. The Reservoir Level Monitoring instrumentation is not a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

4. As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 273) of NE00-31466, and verified by TVA, Reservoir Level Monitoring instrumentation requirements not being met was found to be a non-significant risk contributor to core damage frequency and offsite releases.

Conclusion:

Since the screening criteria have not been satisfied, the LCO and associated surveillance may be relocated to a licensee controlled document.

A-17

APPENDIX A MISCELLANEOUS RADIOACTIVE MATERIALS SOURCES LCO Statement:

The leakage test shall be capable of detecting presence of 0.005 microcurie of radioactive material on the test sample.

Discussion:

The limitations on sealed source contamination are intended to ensure that the total body or individual organ irradiation does not exceed allowable limits in the event of ingestion or inhalation. This is done by imposing a limitation on the maximum amount of removable contamination on each sealed source. This requirement and the associated surveillance requirements bear no relation to the conditions or limitations which are necessary to ensure safe reactor operation.

Com arison to Screenin Criteria:

Miscellaneous radioactive materials sources requirements are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

Miscellaneous radioactive materials sources requirements are not process variables that are initial conditions of a DBA or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. Miscellaneous radioactive materials sources requirements are not part of the primary success path that function or actuate to mitigate a DBA or transient that either assumes the failure of'or presents a challenge to the integrity of a fission product barrier.

4. As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 267) of NEDO 31466, and verified by TVA, the Miscellaneous Radioactive Materials Sources requirements not being met was found to be a non-significant risk contributor to core damage frequency and offsite releases.

==

Conclusion:==

Since the screening criteria have not been satisfied, the Miscellaneous Radioactive Materials Sources LCO and Surveillances may be relocated to a licensee controlled document.

A-18

APPENDIX A 3/4.2.J SEISMIC MONITORING INSTRUMENTATION LCO Statement:

The seismic monitoring instrumentation shown in Table 3.2.J shall be operable.

Discussion:

In the event of an earthquake, seismic monitoring instrumentation is required to determine the magnitude of the seismic event. These instruments do not perform any automatic action. They are used to measure the magnitude of the seismic event for comparison to the design basis of the plant to ensure the design margins for plant equipment and structures have not been violated.

Since the determination of the magnitude of the seismic event is performed after the event has occurred, this instrumentation has no bearing on the mitigation of any design basis accident (DBA) or transient.

Com arison to Screenin Criteria:

1. Seismic monitoring instrumentation is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

2. Seismic monitoring instrumentation is not a process variable that is an initial condition of a DBA or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. Seismic monitoring instrumentation is not part of the primary success path that functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 151) of NED0-31466, and verified by TVA, the loss of the Seismic Monitoring instrumentation was found to be a non-significant risk contributor to core damage frequency and offsite releases.

==

Conclusion:==

Since the screening criteria have not been satisfied, the Seismic Monitoring Instrumentation LCO and Surveillances may be relocated to a licensee controlled document.

A-19

APPENDIX A 3.2.F/4.2.F METEOROLOGICAL MONITORING INSTRUHENTATION LCO Statement The meteorological monitoring instrumentation listed in Table 3.2. I shall be OPERABLE at all times.

Discussion:

Ensures that there is a sufficient amount of data available to estimate potential radiological doses. There are no automatic actions during any event that these instruments perform, nor do they actuate to mitigate a DBA or transient.

Com arison to Screenin Criteria:

1. The Meteorological Monitoring instrumentation is not used to detect, and indicate in the control room a significant abnormal degradation of the reactor coolant pressure boundary (RCPB).

t

2. The Meteorological Monitoring instrumentation is not capable of monitoring a process variable that is an initial condition of a DBA or transient analyses that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. The Meteorological Monitoring instrumentation is not a structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

4. As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 151) of NEDO-31466 (Table 4-1 and 6-3, Item 152), the loss of meteorological monitoring instrumentation is a non-significant risk contributor to core damage frequency and offsite releases.

Conclusion:

Since the screening criteria have not been satisfied, the LCO and associated surveillance may be relocated to the Technical Requirements Manual.

A-20

APPENDIX A 3.8.B.9, 10 RADIOACTIVE MATERIALS - AIRBORNE EFFLUENTS, EXPLOSIVE 4.8.B.5 GAS MIXTURE LCO Statement:

The concentration of hydrogen downstream of the recombiners shall be limited to less than or equal to 4% by volume.

Discussion:

The explosive gas mixture Specification is provided to ensure that the concentration of potentially explosive gas mixtures contained in the waste gas holdup system is maintained below the flammability limit of hydrogen. However, the waste gas holdup system is designed to contain detonations and will not affect the function of any safety related equipment. The concentration of hydrogen in the offgas stream is not an initial assumption of any design basis accident (DBA) or transient analysis.

Com arison to Screenin Criteria:

The explosive gas mixture requirements are not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

2. The explosive gas mixture requirements are not process variables that are initial conditions of a DBA or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. The explosive gas mixture requirements are not part of the primary success path that functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 306) of NED0-31466, and verified by TVA, an explosive gas mixture in the waste gas holdup system was found to be a non-significant risk contributor to core damage frequency and offsite releases.

==

Conclusion:==

Since the screening criteria have not been satisfied, the Explosive Gas Mixture LCO and Surveillances may be relocated to a licensee controlled document.

A-21

APPENDIX A 3.2.F/4.2.F EXPLOSIVE GAS MONITORING INSTRUMENTATION LCO Statement The explosive gas monitoring instrumentation listed in Table 3.2.K shall be OPERABLE with the applicability as shown in Tables 3.2.K/4.2.K.

Discussion:

The explosive gas monitoring instrumentation is provided to ensure that the concentration of potentially explosive gas mixtures contained in the gaseous radwaste treatment system is adequately monitored, which will help ensure that the concentration is maintained below the flammability limit of hydrogen.

However, the offgas system is designed to contain detonations and will not affect the function of safety related equipment. The concentration of hydrogen in the offgas system is not an initial assumption of any design basis accident or transient analysis.

Com arison to Screenin Criteria:

The explosive gas monitoring instrumentation is not used for, nor capable of, detecting a significant abnormal degradation of the reactor coolant pressure boundary prior to a DBA.

The explosive gas monitoring instrumentation is not used to monitor a process variables that is an initial conditions of a DBA or transient.

Excessive system effluent is not an indication of a DBA or transient.

3. The explosive gas monitoring instrumentation is not part of the primary success path that functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (Item 306) of NED0-31466, and verified by TVA, an explosive gas mixture in the waste gas holdup system was found to be a non-significant risk contributor to core damage frequency and offsite releases.

==

Conclusion:==

Since the screening criteria have not been satisfied, the Explosive Gas Mixture LCO and Surveillances may be relocated to a licensee controlled document.

A-22

APPENDIX A 3.10.A.3 & 4 REFUELING PLATFORM EQUIPMENT INTERLOCKS LCO Statement Refueling Interlocks

3. The fuel grapple hoist load switch shall be set at ( 1,000 lbs.

If the frame-mounted auxiliary hoist, the monorail-mounted auxiliary hoist, or the service platform hoist is to be used for handling fuel with the head off the reactor vessel, the load limit switch on the hoist to be used shall be set at < 400 lbs..

Discussion:

Specifies minimum operability requirements. Designed to provide the capabilities to prevent damage to the refueling platform equipment and core internals, they are not assumed to function to mitigate the consequences of a DBA.

Com arison to Screenin Criteria:

1. Refueling platform equipment interlocks are not used to detect, and indicate in the control room a significant abnormal degradation of the reactor coolant pressure boundary (RCPB).

2. Refueling platform equipment interlocks are not capable of monitoring a process variable that is an initial condition of a DBA or transient analyses that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

3. Refueling platform equipment interlocks are not a structure,. system, or component that is part of the primary success path and which functions or actuates to mitigate a DBA or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.

As discussed in Sections 3.5 and 6 and summarized in Table 4-1 (item 306) of NED0-31466, and verified by TVA, the loss of the refueling platform equipment interlocks is a non-significant contributor to core damage frequency and offsite release.

==

Conclusion:==

Since the screening criteria have not been satisfied, the LCO and associated surveillance may be relocated to a licensee controlled document..

A-23

APPENDIX B BFN SPECIFIC RISK SIGNIFICANT EVALUATIONS

APPENDIX B TABLE 3/4.2.B CORE SPRAY SPARGER TO REACTOR PRESSURE VESSEL d/p LCO Statement:

The limiting conditions for operation for the instrumentation that initiates or controls the core and containment cooling systems are given in Table 3.2.B.

Table 3.2.B Instrumentation that Initiates or Controls the Core and Containment Coolin S stems 3/4.2-17 Core Spray Sparger to Reactor Pressure Vessel d/p Descri tion of Re uirement:

This instrumentation measures the differential pressure between the core spray sparger and the reactor pressure vessel above the core plate and alarms if a break is detected. This instrumentation does not actuate any equipment.

Risk Justification:

The function of the instrumentation is to identify a break in the core spray sparger. The probability of a pipe break (EPRI TR-100380) is extremely low, therefore the relative probability as defined in NEDO-31466 is low. LOCAs represent a small contribution to the BFN core damage frequency (CDF). A break in the sparger in the reactor pressure vessel would, without a LOCA, provide injection to the core. Given the success of injection with a break in non-LOCA accidents and the small contribution of LOCA to the CDF, the relative significance from an offsite radiological dose perspective would be low. The risk category would therefore be considered non-significant (NS).

Relative Probabilit Rl 1 Rl 111 ~ltikC Low Low

APPENDIX 8 3/4.2. FLOOD PROTECTION LCO Statement The unit shall be shutdown and placed in the cold condition when Wheeler Reservoir lake stage rises to a level such that water from the reservoir begins to run across the pumping station deck at elevation 565. Requirements for the instrumentation that monitors the reservoir level are given in Table 3.2.H.

Descri tion of Re uirements:

This Technical Specification has provisions for high reservoir water level instrumentation. A high reservoir water level indication is a preliminary indication of a flood. A flood is not a design basis accident or transient, thus reservoir water level is not credited in the safety analysis.

Risk Justification:

An analysis of the risk of external flooding was performed in BFN's Individual Plant Examination of External Events ( IPEEE) for Severe Accident Vulnerabilities. Historical flood data was collected and analyzed to determine the frequency and magnitude of floods at BFN. All critical equipment essential to the safe shutdown of the plant are flood protected to an elevation well above that required in the current LCO. Given the plant design features and the conservative analysis of flooding in the IPEEE, the contribution of flooding to overall plant risk (probability of occurrence and radiological consequence) is considered negligible.

Rl l b bill Rl l l ll l~kbk<<

Low Low B-2

Enclosure V Volume 1S

3Pec 0'& on 3.'f, l NOV 18 1S88 4.6.D. R V v 588 3~+A~ capon 3. The integrity of the 4<<kz<gcs*< 8P< relief valve bellovs shall be continuously l ST 5 Z.g.2, ~ggqg monitored when valves incorporating the bcllovs design are installed.

4. ht least one relief valve shall be disassembled and inspected each operating cycle.

3 6 E 2aMmua E

~Rum'.

Whenever the reactor is in the 1. Whenever there is SThRTUP or RUN modes, all )et recirculation flov vith yumya shall be operable. If the reactor in tha it is determined that a )et STARTUP or RUE aodaa pump is inoperable, or if tvo or more get pump flov instrument vith both recirculation pumps running, 5et yap failures occur and cannot be operability ahall ba corrected vithin 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, an checked daily by orderly shutdown shall be verifying that the initiated and the reactor shall folloving conditions be placed in thc COLD 'SHUTDOWN do not occur al COHDITIOK vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. simultaneously:

~ased log, VC'fig r SRZV.(,l

~SR .,I

~ ~ 4~va racir at

>~ loo taaa-e- flo ~

or <z.

Ius aoea when

'- i%~opera " ~

b. The indicated value Ink ~I~ of core flov rata l~ varies from the value derived froa looy flov measurements by sore than 10K.

c. The.diffuser to lover plan~ di fferantial pressure reading on an individual )ct yump varies from the mean of all ]ct yump by aors than differentia.'ressures 10K.

3.6/4.6-11 BFl Unit 1 AMBINENTIjL Q~

'i AUG 0 4 5$

4.6.Z.

~<<5'uS44'r'Cab'O~ P gQ ~S Whenever there is

~

recirculation flov vith 4 BFd I STS Z,q,~ the reactor in the SThRHJP or RVH Mode and one recirculation pump is operating, the diffuser to lover i plenum differential pressure shall be checked daily and the differential prcssure of an individual

)et pump .in a loop shall Pr~d Qp~ not vary from the mean 6$ R g...) of all get pump differential pressures in that looy by more than 10X.

i

&03igel

1. The

+ mr reactor shall not be operated s, II Recirculation pump s eeds vith one recirculation looy out shall be chewed e

~r;oeie of eerrfoe for sore theo ~boors 2 at least ce pcr ay.

Vith thc reactor operating, if oac recirculation loop is out of service, the ylant shall bc placed in a HOT SHUTDOWNS CONDITION vithia 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless

~

the loop is sooner returned to

. scrvicc.

2~ Fol oviag c y opera on, th dis ge va e of e lov sp ed p may t be o ened css t e spec of th faster p is css 50K of its atsd s aed 3~ Mhaa the rca is n in thc 3. Bcf rc star ing cit r rgC7'>od CUR aode, CTOR POWER OPERATION re rculat on ump D vith both rec rcu at on pumps out- d ing CT0 PO R of-service for uy to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is IO, cck permitted. Dur ag such interval og th loo dis e estart of the recirculation teapc tur and do yumps is permitted, yrovided thc ~ at ati t cra ure.

loop discharge temperature is vithia 7$ 'F of the saturation sec 3MHg'~h'o 4 Qe~gds Pr ggh) (5T5 g tf BEE 3 '/4.6-12 AMENDMENT NO. 2g7 f Unit 1 k.oo

temperature of e reactor vessel vatcr aa determined by d pressure. The tota elapsed time QvioN natural circulation and one pump operation must be no greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4. The reactor shall not be operated vith both recirculation pumps out-of-service vhile the reactor ia in the RUB mode. Polloving a trip of both recirculation pumps vhile in the RUN mode, imnediatcly inftiate a manual reactor scram.

3.6.C 4+6.C The structural integrity of hSNE 1. Inservice inspection of ESNE Code Class 1, 2, and 3 equivalent Code Class 1, Class 2, and components shall be maintained in Class 3 components ahall be accordance vith Specification 4.6.G .performed in accordance vith throughout the life of the plant. Section XI of the hSNE Boiler

'and Pressure Vessel Code and

a. Vith the structural integrity applicable Addenda aa of any ESNE Code Class 1 required by 10 CFR 50, equivalent component, vhich fa Section 50.55a(g)j except part of the primary ayatca, not vhsre specific vritten relief conforming to the above has been granted by HRC requirements, restore the pursuant to 10 CFR 50, structural integrity of the Section 50.55a(g)(6)(i).

affected component to vithin ita limit or maintain the 2. hdditional inspections shall reactor coolant system in be performed on certain either a Cold Shutdovn circumferential pipe vclda to conditfon or less than 50 F provide additional protection above the ainfiime temperature against pipe vhip, vhich requfred by HDT considerations, could damage auxiliary and until each indication of a control systems.

defect haa been investigated and evaluated.

BFS 3.6/4.6-13 AMEKOMHP go p 06 Unit 1

0 S'F'.inca. 'on 3. M HAY 3 1594 SR

<CO l. the reactor shall not be Verify that the reactor is outside of Region I and II operated at a thermal pover Z.Q. ) and core flov inside of of Figure 3.5.5-1I Regions I and II of Figure 3.5.N-l. a. Folloving any increase of aors than 5Z rated ,

2. If Regionis I of Figurc theraal pover vhile initfal core flov fs 3.5.N-1 entered, faaedf ately initiate a less than 45K of aanual scram. rated, and 4An If Region II of Figure b. Folloving any decrease of aors than 10K rated 3.5.8-1 is entered:

8 core flov vhile

a. Iaecdfately initiate initial thermal pover action and exit thc is greater than 40K of re ion vithin 2 u rated.

ert rol ods or by in reasi c c Pcopsr d Qc+'o n flo (sta ting eci culat on p t t ere fon an a 0 fa e ac 00)

LR~

b. While exiting the region, iaaediately initiate a manual acre%

if thcraal-,hydraulf c instability is obserred, as cridcnced by o illa iona ch ed 1 percen pe to-p of r ted or LPRN acfll tions ch exes 30 pc

-

ent peak-t peak seal .

If peri ic LP ups e

. o Qqps e ala oc , 'atel che the APRH's and indi idual RN's r erid ce of .

the -hydraulic tab ity.

NENbggPN. 2p g BlK 3.5/4.5-21 Unit 1

r ~ ~ ~

ill IIIIIII . ~ o

UNIT 2 CURRENT TECHNICAL SP ECIF ICATION MARKUP

0 5 cci figqgjo~ g g /

4 S S 0 HOV 18 1988

-'NITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3 ~ The integrity of the relief valve bellows

+L 4~sfili(qfio~ shall be continuously 4r No~g~gg~ monitored when valves incorporating the bellows Bylaw ISIS g yZ design are installed.

3.g 3 4~ At least one relief valv shall be disassembled and inspected each operating cycle.

3.6.E. ~Jt Pupas E. ~Jet um Whenever the reactor is in the Whenever there is STARTUP or RUH modes, all jet recirculation flow with pumps shall be OPERABLE. If the reactor in the it is determined that a jet STARTUP or RUH modes pump is inoperable, or if two with both recirculation or more jet pump flow instrument pumps running, jet pump failures occur and cannot be operability shall be corrected within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, an checked daily by orderly shutdown shall be verifying that the initiated and the reactor shall following conditions p ~~ ~g be shutdown in the COLD SHUTDOWN do not occur *-sa~.V.l.i COHDITIOH within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. simultaneousl ~

~~5~ti 4 /. v'cr.C 'Lb

a. The %vo ec rcu ation loopg %ave-a flow ~:s~gt;>

kgb ~.

.~opera when

~he-or ii ge h

c,e J.4, The dicated value !OOP of core flow rate varies from the value derived from loop flow measurements by more than 10X.

c. The diffuser to lower plenun differential pressure reading on an individual jet pump varies from the mean of all jet pump differential pressures by more than lOX.

BFH 3 6/4.6-11 hMMmetn. %la Unit 2

AUG 04594 A'l 4 '.E.

2~ Whenever there is 3854AL40~ fol recirculation flov vith

+a Q phJ the reactor in the SThRTtJP or RUR Mode and one recirculation pump ia operating, the diffuser to lover plenum differential pressure shall bc checked daily and the differential pressure of an individual Ql.l )et pump in a loop shall not vary from the mean Pape@ Nk of all )et pump

~ sR p.g.f.i differential pressures in that loop by more lOX.

QAI ~ 0 ~

LCO 8.4 ) a4.44 Qo~~ ~:~~ RZ. 9. V.//

1. The reactor shal not be operated Recirculation pump ayceda vith one recirculation loo out M2. shall be checked of service for more 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. A> at least once per With the reactor operating, one recirculation loop is out of A3 service, the plant shall be placed in a HOT SHUTDOWR COHDITIOR vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless the loop ia sooner returned to service.

Pollov ng one pump operation, the d achargc va e of the v Al ape yump may t be open sa thc sp d of the f ter y ia less SO% of its eated speed.

30 'Whan tha reactor ia not in the RJJK mode GTOR POWE QVIOQ. HDtATIOR o recircu- 3~ Bcfor starting, either D,, on yea out~f-service Foci ation for uy to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> ia crmitted. dur REi POWER au interval, restart o R2 0 OE, ck thc racirculation pumps ia 1 thc lo y dia gc permitted, provided the loop tcmyerat c and d ia vithin saturation temperature 2'f thetemperature diachare saturation

'5

~

temperature of the reactor Btà 3 ~ 6/4.6-12 Unit 2 c 5th W~d'IfiCagi~

4~ BF< IsM z.9

~~< C4~

9 gg

Z eE<<$ ,. >.V. I NR i 8 1993 3~ ~

Secs. ~);C;,.4;og. CE vessel water as determined 4a< SftJ Lszg by dome pressure The total e apsed time in natural gcgm8 circulation and one pump +I h operation must be no greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4. The reactor shall not be operated with both recirculation pumps pgsiod out-of-service while the E reactor is in the RUN mode. Following a trip of

.G'.6.G both recirculation pumps while in the RUN mode, ismediately initiate The a manual reactor scram.

structural integrity of ASME Code Class 1, 2, and Inservice inspect,ion of Code Class 1, Class 2, and ASIDE 3 equivalent components shall Class 3 components shall be be maintained in accordance performed in accordance witt with Specification 4.6.G Section XI of the ASME Boil~

throughout the life of the and Pressure Veseecl Code anc plant. applicable Addenda as requi:

by 10 CFR 50, Section 50.55c

a. With the structural except where specific writtc integrity of any ASME relief has been granted by 1 Code Class 1 equivalent pursuant to 10 CFR .50, Sect:

component, which is part 50.55a(g)(6)(i).

of the primary system, not conforming to thc above requirements, restore 2. Additional inspections the structural integrity of shall be performed on thc affcctcd component to certain circumferential within its limit or maintain pipe welds to provide thc reactor coolant system in additional protection either a COLD SHUTDOWN against pipe whip, CONDITION or less than 50'F which could damage above thc minimum temperature auxiliary and control required by NDT consider- systems.

ations, until each indication of a defect hae been inves<<

tigatcd and evaluated.

Se~ ~iS4eyio- 4r C~~-gez

• ~ cw5 Z.4.p//Q gi )

BFÃ ~"'~ Sec~ii< 3 6/4 6-13

~ AMENDMENT lE 8 0 6 Unit 2 PAGE

FEB 2 4 1995 Ai L. t o L.

l. Whenever the core thermal FRP/CMFLPD shall be pover is g 25Z of rated, thc dctermincd daily vhen

'ratio of FRP/CMFLPD shall the reactor is g 25Z of bc Z 1.0, or thc APRM scram rated thermal pover.

sctpoint equation listed in Section 2.1.k and the APRM rod block setpoint equation listed in the CORE OPEKLTIHG LIMITS REPORT shall be multiplied Qg J ~gk Cite,ly~ fir CA'<7Q by FRP/CMFLPD. 4~ 8~N isis z.z.f

2. Shen it is determined that 3.5.L.1 is not being, mct, 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is allovcd to correct the condition.

3. If 3.5.L.1 and 3.5.L.2 cannot bc mct, the reactor povcr shall be reduced to g 25X of rated thermal pover vithin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

Ai Sg'.0. I- 2.

/CO 1. Thc reactor shall not bc 1. Verify that the reactor is operated at a thermal povcr outside of Region I and II and core flov inside of of Figure 3.5.N-1:

Regions I and II of Figure 3.5.N-1. a. Follovtng any increase of more than SX rated

2. If Region I of Figure 3.5.N-1 thermal povcr vhile core flow is less A is entcrcd, immediately 'nitial initiate a manual scram. than 45X of rated, and

3. IfZe~g II of. Figurc 3.5.N-1 b. Follovtng any decrease is 'entered: of more than lOX rated core flow vhilc initial thermal povcr is greater than 40X of rated.

2S2 BFH Unit 2 3 '/4.5-20 aemoMapgo.

5 ',

N OO 3 ~ ~ ~

a. Immediately initiate action yq IG~ and exit the region vithin 8 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> nsert ng con ro o s or b increas ng cor f v.('tar g a re rcu-1st ~n pump exit t region s ~ot an appropriate action) and

b. While exiting the region, immediately initiate a manual scram if thermal-hydraulic instabilit is obse as evidenc d by AP oscil a-ti ns vh ch excee 10 p cent pea -to-p ak of r ed or PRN osci atio vhich exceed 30 pe ent eak-to- eak of cale. 'Cf p riodic LP3X scale r d vnscale alarms oc r, edi ely ch ck the APRM and ndi idual ARM's for e denc of thermal-hydraulic ins ability.

BFN 3;5/4.5-20a Unit 2

3.V. (-(

Fi ure BEN Power I=low Stabilii:y Regions 100 .

9Q ~ 00000 ~~0 000 ~0 ~0 ~0~ ~0 ~0 ~ ~

100% Rod Line 80- ~ ~0 ~ ~ 0 ~ ~ 0 ~ 000 f 000 ~ 000 ~

g

~ 0 ~0 ~0 ~ 0 CJ 70- ~~ \ ~0 ~

IO OperoVion Not 0 60; ---- Note: Permitled in ~0 ~ ~0 ~

C TI>is Region 807. Rod Line 6)

O

0) 50. ~ ~~ ~

CL ID 40- . ~ ~

0 CL 0) 0 30- -.

(3 Noturol

(:irculotion, 00 0~~ ~ 00 ~~~~ ~ ~ ~ ~ oo ~ 0 ~ ~ ~

Line ~ ~ ~ ~~~ \~~ ~~ ~~

~eend ~ ~ ~ ~~~0~ 0~~ ~ ~ ~ ~ 0 2Q l[jggm Raijion Io CD Rnoion ~ ~ C3 10- ~~ ~~~ 00 ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~

.R 0

0 0

PP~

5 10 I

15 01 ~ tW 20 25 30 35 40 45 50 55 60 65 /0 r ~~ rm r~<~~

/5 80 85 90 95 100 10 5 CTl Core Flow (perrcnt of rnted)

0' UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

SPeC Plea.

OY 18 tS88 NG CO TONS FO 0 ON SUR C See 3WS+06CC fjOn 3. The integrity of the 4e ~eS+r relief 1sT5 s.e.x 30 9e

~tlPA valve bellows shall be continuously monitored when valves incorporating the bellows design are installed.

4. At least one relief valve shall be disassembled and inspected each operating cycle.

3.6.E. J~ee Pum E. J~e~im~

1. Whenever the reactor is in the Whenever there is STARTUP or RUN modes, all jet recirculation flow with pumps shall be OPERABLE. If the reactor in the it is determined that a jet STARTUP or RUN modes pum'p is INOPERABLE, or if two with both recirculation or more jet pump flow instrument pumps running, jet pump failures occur and cannot be operability shall be corrected within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, an checked daily by orderly shutdown shall be verifying that the initiated and the reactor shall following conditions be placed in the COLD SHUTDOWN do not occur

! CONDITION within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. simultaneously:

'

583.']. I-I a X~voy +~

ecirculati oops hes~a flow~

]of (s

4504K. when 4',

or l]

~opera 1 6C tC'E.E nu+lc El

b. The indicated value of core flow rate varies from the value derived from loop flow measure-ments by more than lOX.

c. The diffuser to lower plenum differential pressure reading on 0 an pump mean individual jet varies from the of differential all jet pump pressures by more than 10K.

BFN 3.6/4.6-11 AIAENDINBII'5.1 99 Unit 3

~~a= ..&

0 h

QPgc'gjcctM'1 3b / ~ (

BO ARY AtJS 04594 Ai I

4 6 E. ~Jam

2. Whene ver there is 5Ll564i4AW oA 6< recirculation flow with the reactor in the Cl ~es e Bknl t S TS STARTUP or RUH Mode and Z.9- '2- one recirculation pump is operating, the diffuser to lower plen~ differential pressure shall be checked daily and the L differential pressure of an individual jet pump in a loop shall fTO)05ed @ok not vary from the mean 6 5R 3A.I.I of all get pump differential pressures in that loop by more than 10K.

i co z.e.( R4c eeerrrrm rrrr ~lrr2 SR3.~ I l

1. The reactor shall not be operated 1. Recirculation pump with one recirculation loop out speeds shall be checked of service for more than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 'm 1 at east With the reactor operating, one recirculation loop is out of if nce er a C +g service, the plant shall be Laz.

placed in a HOT SHUTDOWH COHDITIOH within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless the loop is sooner returned to service.

2. F liow ng e-p p o era ion, e sch ge alve of e 1

~LA I pe p m no be pene un ss e eed f e f te p p i le s t 5 of ts ate spe d.

3. When th eactor is not-'in th RUH 3. Bef e st rti eit er ACTIN al mode, REACTOR POWER OPERATIO with re rcu tion pum D both recirculation pumps out-of- d ing CT P R service for u to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is ERA OH, e and permitted. uring such interval og e lo p d cha ge estart of the recirculation pumps tern ratu e do e is permitted, provided the loop saturation tempe ture.

discharge temperature is within 75'F of the saturation temperature See yooiiCrcrHon for <largP BFN Unit 3 6" BFN ~SYS Z.H.9

0 See 5~sWWog fc~

of the reactor vessel water determined b dome ress The

~~< krBPN igTsp q.q, Agio g tota e apsed time fn natural D circulation and one pump operation must be no greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4~ The reactor shall not be operated with both recirculation pumps AC4'oui, out-of-service while the reactor E is in the RUH mode. Following a trip of both recirculation pumps while in the RUH mode, immediately initiate a manual reactor scram.

3.6.G S ctu 4.6.G The structural integrity of ASME l. Inservice inspection of ASME Code Class 1, 2, and 3 equivalent Code Class 1, Class 2, and components shall be maintained Class 3 components shall be in accordance with Specification performed in accordance with 4.6.G throughout the life of the Section XI of the ASME Boiler plant. and Pressure Vessel Code and applicable Addenda as required

a. With the structural integrity by 10 CFR 50, Section 50.55a(g of any ASME Code Class 1 except where specific written "equivalent component, which relief has been granted by HRC is part of the primary system, pursuant to 10 CFR 50, Section not conforming to the above 50.55a(g)(6)(i).

r'equirements, restore the structural fntegrity of the 2. Additional inspections shall b affected component to within performed on certain fts limit or maintain the circumferential pipe welds reactor coolant system in either to provide additional a Cold Shutdown condition protection against pipe whip or less than 50'F above which could damage auxiliary the miniinm temperature and control systems.

required by HDT consfder-ations, until each indication of a defect has been investigated and evaluated.

See S~W'cOHo+ 6~

ch ~ys 6 cps s.<%6. r..G in yh;S geC4og BFH 3.6/4.6-13 ANBMgrNO. y 79 Unit 3 paG

0

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E JUSTIFICATION FOR CHANGES BFN ISTS 3.4.1 - RECIRCULATION LOOPS OPERATING ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in 'a technical change.

CTS requires the plant to be placed in the HOT SHUTDOWN CONDITION in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with one recirculation loop out of service. Proposed ACTION C requires the loop be returned to service in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or ACTION D requires the plant to be in MODE 3 (Hot Shutdown) in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The CTS and the proposed ISTS Completion Times are essentially equivalent since both require the plant to be in MODE 3 in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

A3 The frequency for this Surveillance has been changed from once per day to once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This is a terminology change and is therefore administrative.

TECHNICAL CHANGE - MORE RESTRICTIVE CTS allows up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> operation with the reactor power < 1% with no recirculation loops operating (the total elapsed time in natural circulation and one pump operation must be no greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />).

Proposed ACTION D is more restrictive since the time limit of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> applies to < 1% while in MODE 2 also.

0 Revision 0 BFN-UNITS 1, 2, 5. 3 Pi,GE Vt 3

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.1 - RECIRCULATION LOOPS OPERATING H2 The flow imbalance limit is being reduced to 10% of rated core flow when operating at < 70% of rated core flow, and to 5% of rated core flow when operating at a 70% of rated core flow. The current requirement is 15%

mismatch of flow at the given flow conditions. While the limit appears to be less restrictive if core flow is x 66% of rated core flow, it is more restrictive when'> 66% of rated core flow (i.e., 15% x 66% or less is x 10% of rated core flow), where the unit normally operates. In addition, currently, this is only a problem if there is an imbalance in combination with two other conditions (CTS 4.6.8. l.b and c). The new requirement is separate from the other two, thus, actions will now be required if there is an imbalance by itself. Therefore, this change is considered more restrictive on plant operations.

TECHNICAL CHANGE - LESS RESTRICTIVE "Generic"

~ LA1 This requirement is being relocated to plant specific procedures.

purpose of this limitation is" to provide assurance that when shifting from one to two loop operations, excessive vibration of the jet pump risers will not occur. Short term excessive vibration should not result The in immediate inoperability of a jet pump, but could reduce the lifetime of the jet pump. This type of requirement is generally found in plant operating procedures, similar to other operating requirements necessary to minimize the potential of damage to components. Changes to the procedures will be controlled by the licensee controlled programs.

LA2 This requirement is being relocated to plant specific procedures.

Details of the methods for performing this Surveillance, and any requirement to record data, has been relocated to plant procedures. Any changes to the procedures will be controlled by the licensee controlled programs.

LA3 These requirements are being relocated to plant specific procedures.

The details of the acceptable method for meeting an action requirement and what constitutes evidence of thermal hydraulic instability and the need to check for it have been relocated to plant procedures. Any changes to the procedures will be controlled by the licensee controlled programs.

PAGE~OP BFN-UNITS 1, 2, 5 3 Revision 0

Cl JUSTIFICATION FOR CHANGES BFN ISTS 3.4.1 - RECIRCULATION LOOPS OPERATING "Specific" Ll This change adds a note which states the Surveillance is not required to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after both recirculation loops are in operation. The Surveillance is not required to be performed until both loops are in operation since the mismatch limits are meaningless during single loop'or natural circulation operation. Also, the Surveillance is allowed to be delayed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after both recirculation loops are in operation. This allows time to establish appropriate conditions for the test to be performed.

L2 Per CTS 3.5.M.3.a, if Region II of Figure 3.5.M-1 is not exited within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, the Specification is violated and CTS 1.O.C. 1 applies requiring the plant be placed in Hot Standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Cold Shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. This provides actions for circumstances not directly provided for in the specifications and where occurrence would violate the intent of the specification. The BFN ISTS provides Action within the Specification which could be considered less restrictive than CTS. Action 0 allows 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to be in MODE 3 (Hot Shutdown) and 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> to be in MODE 4 (Cold Shutdown). The proposed Action is considered less restrictive since 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is allowed to place the unit in Hot Shutdown versus the 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowed to place the unit in Hot Standby per CTS.

BFN-UNITS 1, 2, & 3 Revision 0

UNIT 1 CURRENT TECHNICAL SP ECIF ICATION MARKUP

NOV Z8 1988 4.6.D. R e Va ve 3 ~ The integrity of the relief valve bcllovs 5'C'('~c+',4;(c,h~ shall be continuously

+~$ <o +<

p monitored vhen valves BP+ ILATS 3,q, incorporating the belloys design arc installed.

4~ At least onc relief valve shall be disassembled iowan and inspected each o erati c cle.

Vcn c&oLht.o~(. of-lt~~i ~P C~ehn~

LCo 3.9.2 Mti o~ee Fi'CA (eLcg 0A Whenever thc reactor is in thc enevcr there is Rgplicab'1'kj STARTUP or RUH modes, all,)et ecircu ation flov vith umps shall be operable. If he re ctor th it is determined that a jet TAR or cs pump is inoperablc, r tv ith 0th ecir Lt or re t pump ov t cnt um s ingg ct fa urea occur d c ot c op rabil s 11 b rec d 12 ours an checked aily order y shutdovn shall bc vcrifyi t th initiated and the reactor shall follov ng c diti

'be placed COHDITIOH in the~ ours.

vithin HUTDOWH do not occ simultaneously:

a. The tvo recirculation loops have a flov imbalance of 15X or morc vhen the pumps

~e Y~ShA(cfhon 4,f- ~~> arc op~rated at th gci gPN LS75 p,q. ~ s ccd

b. The indic ted value of orc ov ate frogoCd <R >'t > I IJokS v ies rom e luc eriv f oop ov g2 ftopsH SP Z.9.3. I mess em ts more han 10K l.$ . The dfffeeer eo lower plenum differential pressure reading on an individual )et p eke cc~]isa& varies from

%Pe v 3.6/4.6-11 C g less g2.

BFH Unit 1 NENOMENT NL I5 8

Se>> iP; on 5.,z AUB 04 1994

~se ev r t ereyis cu ti A,o vith

~lICab;fig thc reactor in the

~ STARTUP or RUR Mode and n rec culat n um 8

diffuser to lover plenum differential pressure shall be checked a and thc differential pressure of an individual

~k~ >m Isis 8pnl Z~Von 4- C/g~~

z.g,~

get pump .in a loop shall vary from of all get p m

dif er tial (mesa rea t t o by eave

~

z ~ass t}x 3.6.F 4.6.F

1. The reactor shall not bc operated 1. Recirculation pump speeds vith one recirculation loop out shall be checked a'nd logged of service for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. at least once per day.

With the reactor operating, onc recirculation loop is out of if service, thc plant shall bc placed in a HOT SHUTDOWN CORDITIOR vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless the loop is sooner returned to service.

2. Folloving one pump operation, 2. Ro additional surveillance the discharge valve of the lov required.

speed pump may not bc opened unlesa the speed of thc faster pump is less than 50Z of its

.rated speed.

3. When the reactor%a not in thc 3. Before starting either RUE mode, REACTOR POWER OPERATIOR recirculation pump vith both recirculation pumps out- during REACTOR POWER of-service for up to 12 hours is OPERATIOK, check and permitted. During such interval log thc loop discharge restart of the recirculation temperature and dome pumps ia permitted, provided thc saturation temperature.

loop discharge temperature is vithin 75'P of the satu BFK 3.6/4.6-12 AMENDMENT No. 2gy Unit 1

. 3- 5

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP PAGE~GP~

0 s

NOV 18 1S88 ION 4.6.D. e Va ves 3 ~ The integrity of the 5'VC7 lgjCA7 IohJ relief valve bellovs shall be continuously Fog ~ho/~ /or monitored vhen valves B j=w incorporating the bellows design are installed.

4~ At least one relief valve shall be disassembled and inspected each' erati c cle.

Al c Q ak o<c.

~ ~ ~

C1.4'ra Lu) 3.VZ lS Sa 'l<gg~

I-~ Whenever the reactor is in the enever t CI h'4 i ~vkg ~ //os Apl'c4'.j,g STARTUP or RUH modes, all jet recircul ion flov vith pumps it is shall be OPERABLE. If the re tor in the determined that a Jet TAR or RUH modes pump is inoperable or i~two it both rec culation or ore get pump flov instibment p ps runni, get pump failu s occur~ cannot operabili shall be orrecte vithin 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> an checked aily b orderly shutdown shall be veriiyi tha the initiated and the reactor shall follovfng c ditions be shutdown in the 66BB- HUTDOWH do not occur COHDITIOH vithi hou

/2.

a. The tvo recirculation loops have a flov imbalance of 1SX or more vhen the pumps ad QuST(@CA Tkr& FbA C4<u~ are operated at the same s eed.

84, BFH'ggg g g.]

Prolog~

b. The i icated value of c re flov ate 4~ ~~ SW Sa S.MZ.I No4S ~ var es from v ue deri ed ir e.

m oop flo measurements by more SR 3.42.

Sg. 3.Q 2./ The diffuser to lover plena

~dc differential pressure reading on an individual et y$ ~ ~

varie from as' I~4/ pump p ffcr~

by p.

BFH Unit 2 3.6/4.6-11 IL 54

/'MENDMEÃf I

Al D ~

sg 3.Cz,l Wh never there is reci c atioWflo vith reactor in the

"'"'~ ] the

M (STARXUP or RUH mode one~ec ~u at o~uidp

~

o erati , t c diffuser to lover plenum differential pressure shall be checked pS @~ail and the differential pressure of an individual jet pump in a loop shall SeeadÃc4m fc ~ BFN Is~

4

~ 'I. J

~a o vary from e me all )et ump

-di ential essurc loop y than ~

C5 2d L3 3.6.F t 0 t 4.6.F.

1. The reactor shall not be operated 1. Recirculation pump speeds vith one recirculation loop out shall be checked and logged of service for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. at least once per day.

With the reactor operating, one recirculation loop is out of if service, thc plant shall be placed in a HOT SHUTDOWH COHDITIOH vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless the loop is sooner returned to service+

2. Folloving one pump operation, 2. Ho additional surveillance the discharge valve of the lov required.

speed pump may not bc opened unless thc spccd of the faster pump is less than 50K of its rated speed.

3. When thc reacHmis not-in the RUE mode, REACTOR POWER OPERATIOH vith both recircu- 3. Before starting cithcr lation pumps out-of-service recirculation pump for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is permitted. during REACTOR POWER During such interval, restart of OPERATIOH, check and the recirculation pumps is log the loop discharge permitted, provided the loop temperature and dome discharge tempcraturc.is vithin saturation tcmpcraturc.

75 F of thc saturation temperature of the reactor BFH 3. 6/4. 6-12 AMENOMENr N. 2 2 g Unit 2

.3 ..

0, UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

0!

5 e 'A'cn ',g.g HOV18 1S88 4.6.D. Re e Va ves integrity of

~

3 ~ The the See ~~ggg relief valve bellows

+~ Shd shall be continuously IS TS yq.g monitored when valves incorporating the bellows design are installed.

4. At least one relief valve shall be disassembled and inspected each operating cycle.

QA> gtt 4 ))auo'f~

lcf36+o~

6 Ecole,g 2.

enever the reactor is in the enev r TARTUP or RUH modes, all jet recir ulati n fl w t

~ pumps shall be OPERABLE. If the eact in he t is determined that a jet ST TUP R mo es pump is INOPERABLE or w th bo re rc at n or fai et pf wist ure occu and anno be nt umps ilit i , et p oper s 11 orr cte with s an che ed ily by order y s utdown shall be veifyi t t t initiated and the reactor shall f liow ndi o be placed in the HUTDOWH o no oc r CONDITION within ou simultaneousl Iz Ito7. '.

The two recirculatio loops have a flow imbalance of 15K or

~de +reeH~ifrrfroe gr Cluepr more when the pumps are operated at the

+~ 8PN. Is<5 g,q.i same speed.

b. e n at d lu J-Z Ifogsbcd 5R 3.9.g,( Plpkg of or fl w at v ie fr m he lu d iv d f om oo f w eas re-m ts y or than 1 X.

sa e.~,>>

The diffeeer re lever plenum differential pressure reading on an individual jet pump varies fire+ +ho flC csW0Q4e fh Hrea than ~ 40'/o la>>

+t-~ f 29,;

BFH 3.6/4.6-11 Unit 3 AMENOMHfTNi)

P/s

~ ~

Ccs c ~ ~

AUS 0 4 594

~ ~ ~

SR cn er her is rc at on ov vith Ay~;cog],'Q~) the reactor in he C STARTUP or RUH Mo and e c ula i o c ati the di fuser to lover plenty differential pressure shall be che ail and the differential prcssure of an individual jet pump in a loop shall

/}C va fro t m 5<+ YuSkjkicaHon h r t:kpeg of a et ump

+~ 8~ h3 ift cr tial s e l SVS 8 N.1 t o by move than 3.6.F e c at 0 a o 4.6.F t o

1. Thc reactor shall not be operated 1. Recirculation pump vith one recirculation loop out speeds shall be checked of service for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. and logged at least With the reactor operating, one recirculation loop is out of if once per day.

service, the plant shall be placed in a HOT SHUTDOWH COHDITIOH within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless thc loop is sooner returned to service.

2. Folloving one-pump operation, 2. Ho additional the discharge valve of thc lov surveillance required.

speed pump may not be opened unless thc speed of the faster pump is less than 50X of its rated speed.

3. When the reactor is not "in the RUH 3. Before starting either mode, REACTOR POWER OPERATIOH vith recirculation pump both recirculation pumps out-of- during REACTOR POWER service for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is OPERATIOH, check and permitted. During such interval log thc loop discharge restart of the recirculation pumps temperature and dome is permitted, provided the loop saturation temperature.

discharge temperature is vithin 75'F of the saturation temperature BFH Unit 3 3.6/4.6-12 a~arn~mt vo. i 8C

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.2 - JET PUNPS ADNI NI STRATI VE Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readil'y readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change..

The wording of the surveillance was changed to require verification that one of the following criteria are met rather than verifying that none of the conditions exist simultaneously. This is consistent with NUREG-1433 which attempts to phrase everything in a positive manner. Due to the change in phrasing of the Surveillance, "more than" was changed to "less than or equal to" in criteria b and c.

A3 The variance of the diffuser-to-lower plenum differential pressure reading on an individual jet pump will now be taken from the established pattern rather than from the mean of all jet pump differential pressures. This change is in accordance with the recommendations of SIL-330 and NUREG/CR-3052 and is consistent with NUREG-1433.

A4 The conditions of the Surveillance Requirement are assured by LCO 3.4. 1.

Therefore, there is no need to restate the conditions for jet pump operability.

A5 The frequency for this Surveillance has been changed from daily to once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This is a terminology change and is therefore administrative'.

BFN-UNITS 1, 2, 5 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.2 - JET PUMPS TECHNICAL CHANGE - MORE RESTRICTIVE Ml The requirement to place the plant in a Cold Shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when a jet pump is inoperable has been revised to reflect placing the plant in a non-applicable condition. Current Specification 1.0.C.1 states action requirements are applicable during the operational conditions of each specification. Therefore, the requirement to place the plant in Cold Shutdown is not applicable after Mode 3 is reached.

The 'revised action requires plant power to be brought to Mode 3 (outside the applicable condition) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The current action allows 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to place'he plant in a non-applicable condition. As such, this is an additional restriction on plant operation which constitutes a more restrictive change.

This change adds two requirements to the Surveillance to detect significant degradation in jet pump performance that precedes jet pump failure. The first requirement added would detect a change in the relationship between pump speed, and pump flow and loop flow (difference

> 5%). A change in the relationship indicates a plug flow restriction, loss in pump hydraulic performance, leakage, or new flow path between the recirculation pump discharge and jet pump nozzle. The second requirement added monitors the jet pump flow versus established patterns. Any deviations > 10% from normal are considered indicative of potential problem in the recirculation drive flow or jet pump system.

These two added requirements to the Surveillance help to detect significant degradation in jet pump performance that precedes jet pump failure. Requirements added to Surveillance Requirements constitute a more restrictive change. In addition, CTS 4.6.E. 1 allows jet pump operability to be verified by demonstrating that the two recirculation loops. have a flow imbalance of s 15% when the pumps are operated at the same speed. This is now a separate requirement (Proposed SR 3.4.1.1 See M2 of the Justification for Changes for Specification 3.4. 1) and can no longer be used by itself to demonstrate jet pump operability. This change is consistent with NUREG-1433.

SIL-330 provides two alternate testing criteria (thus the deletion of current Surveillance 4.6.E. l.b). One method uses easy to perform surveillances with strict limits to initially screen jet pump operability (the proposed changes above). If these limits are not met, another set of Surveillances exist (current Technical Specifications).

Revising the Surveillances to separate the flow imbalance test requirement and to include the stricter limits reflects a more 0 restrictive change.

BFN-UNITS 1, 2, L 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.2 - JET PUMPS TECHNICAL CHANGE - LESS RESTRICTIVE "Specific" Ll This change deletes the current shutdown requirement associated with jet pump flow indication. Currently, when required jet pump flow indication is lost, an orderly shutdown must be initiated in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and the reactor is required to be in Cold Shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (since Mode 3 is the non-applicable mode, then 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed to reach Mode 3; see discussion of change Hl for ITS 3.4.2). The proposed Specification implicitly requires the jet pump flow indication to be operable only for the performance of the Surveillance Requirement. If the flow indication is inoperable when the surveillance is required to be performed and jet pump flow can not be determined by other means, the jet pump would be decl'ared inoperable and the appropriate actions would be followed. Since the proposed jet pump surveillance requirement is required to be performed every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (the 25% extension per SR 3.0.2 can be applied) and the Required Actions require the reactor to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, the maximum difference in the current Specification and the proposed specification is 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. As a result, the proposed specification effectively allows a maximum of an additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (which is the 25% extension) to reach a non-applicable Mode if a required core flow indicator is inoperable and jet pump flow can not be determined. Depending on when the failure occurs, 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is the maximum increase over the current Specifications (failure occurring immediately after the surveillance is performed). The following table provides the details of the calculation of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> period:

Current Tech Specs Proposed Tech Specs Time 0 hour0 days <br />0 hours <br />0 weeks <br />0 months <br />s- Jet Pump . Time 0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> - Jet Pump Indication Fails Indication Fails

- 12 hr AOT Begins (Immedi ately After SR Time 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />s- 12 hr AOT Expires Time 30 hour3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />s- SR due; Flow

- 24 hr AOT Begins (24 hrs x Indication Inop to MODE 3 (per 1.25) - 12 hr AOT to 3.0.A; see Ml) MODE 3 Begins Time 36 hour4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />s- 24 hr AOT Expires Time 42 hour4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br />s- 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> AOT Plant in MODE 3 Expires Plant in MODE 3 BFN-UNITS 1, 2, & 3 Revision 0

JUSTIFICATION FOR .CHANGES BFN ISTS 3.4.2 - JET PUMPS As depicted above, 42 hours4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br /> is the maximum time that would be allowed if a required jet pump flow indicator is inoperable and jet pump flow can not be determined. Currently a maximum of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> is allowed if more than one jet pump flow indicator is inoperable. Jet pump flow indication operability does not directly impact jet pump operability.

Jet pump flow indication is only required to perform the jet pump Surveillance (SR 3..4.2. 1). SR 3.4.2. 1 verifies jet pump operability and has a frequency of every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> frequency plus the 25%

extension has been shown by operating experience to. be timely for detecting jet pump degradation and is consistent with the surveillance frequency for recirculation loop operability verification. The most common outcome .of the performance of a surveillance is the successful demonstration that the acceptance criteria are satisfied. This change is consistent with NUREG-1433.

L2 Note 1 allows this Surveillance not to be performed until 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the associated recirculation loop is in operation, since these checks can only be performed during jet pump operation. The 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is an acceptable time to establish conditions appropriate for data collection and evaluation. Note 2 to proposed SR 3.4.2. 1 provides time to perform the required. Surveillance when the reactor exceeds 25% RTP. Below 25%

RTP, low jet pump flow results in indication which precludes the collection of repeatable and meaningful data. The flexibility to proceed to a 25% RTP and then commence the SR every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is consistent with approved Technical Specifications for both Perry Nuclear Power Plant and River Bend Station.

L3 The allowed difference between each jet pump diffuser-to-lower plenum differential pressure to the loop average has been increased to 20%.

This change is consistent with the recommendations of SIL'-330 and NUREG/CR-3052 (Closeout of IE Bulletin 80-07: BWR Jet Pump Assembly Failure). SIL-330 specifies a 10/ criteria for individual jet pump flow distribution. When measured by jet pump diffuser-to-lower plenum differential pressure, the equivalent limit is 20% because of the relationship between flow and delta-P. Since BFN uses the diffuser-to-lower plenum differential pressure measurement, the variance allowed should be 20% as recommended by SIL-330 and NUREG/CR-3052. This is a relaxation from existing requirements, therefore, it constitutes a less restrictive change. This increase in allowed difference is considered an acceptable criterion for verifying jet pump operability and is consistent with the BWR Standard Technical Specifications, NUREG 1433.

BFN-UNITS 1, 2, & 3 Revision 0 PAGE

UNIT 1 CURRENT TECHNICAL SPECIFICATION .

MARKUP

OEC 0 7 1SS4 F 6.C 4 '.C 2~ Anytime irradiated fuel is in 2. With the air sampling the reactor vessel and reactor sys tern inoperable, grab coolant temperature is above samples shall be 212'F, both the sump and air obtained and analyzed sampling systems shall be at least once every 24 OPERABLE. From and after the hours.

date that one of these systems is made or found to be inoperable for any reason, the reactor may remain in operation during the succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Ac 5'usaf'i~tjon gag Qqg for the sump system or 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> I HPFA)ST> pgq y~~~

for the air sampling system.,  !

The air sampling system may be removed from service for a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for calibration, function testing, and maintenance without providing a temporary monitor.

3 ~ If the condition in 1 or 2 above cannot be met, an orderly shutdoml shall be initiated and the reactor shall be placed in the COLD SHUTDOWN CONDITION within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. I Qai SR 3.ge3ol 4Me3 in A proxy e y one-half I>br s AH of all re ief va es o relief alve sha 1 be b ch-ch ked

1. When is kno~ to be failed, an or r laced with a A<Ho 8 eck ve orderly shutdo~ shall be R i iti epressurize and the reactor o less than 105 A2 each operatin All val es c cle.

11 have L2 w th hour en heck or e s ae ot eq red r lac d up the to b OP LE in e C co let on of ever IT N. ecnd c es l,243 SR7'l 3 ~2 In accordance vith Specification MM each relief valve shall be manually opened tfopScl t'1 t e oco ples nd SR s.q',g,~ ac stic moni rs d str am of the alve i dica e ste is lookin f the a lve .

BFN 3.6/4.6-10 AMENDMENT NL 2 Z3 Unit 1

0 gkl NOY 18 1988

3. e i tegr y of the elie val e bel ovs shal be ontin ousl mo tore vhen alv in orpo ating he b 1 ws desi r tall d.

At leas o rel ef al e s all e sass bl d d i ted ach oper tip c e.

3 6 E Jm~muu E. ~Jet

1. Whenever the reactor is in the 1. Whenever there is STARTUP or RUH modes, all get recirculation flov vith pumps it is shall be operable. If the reactor in the determined that a )et STARTUP or RUH modes pump is inoperable, or if tvo vith both recirculation or more Jet pump flow instrument pumps running, get pump failures occur and cannot be operability'hall be corrected vithin 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, an checked daily by orderly shutdown shall be verifying that the initiated and the reactor shall folloving conditions be placed in the COLD SHUTDOWH do not occur COHDITIOH vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. simultaneously:

a. The tvo recirculation loops have a flov gee rw+,'p; (qp<g~ imbalance of 15Z or more vhen the pumps

<+es tr> 8cnr lSTS are operated at the

~ s.z. r+ P~ps same speed.

b. The indicated value of core flov rate varies from the value derived from loop flov measurements by more than 1OZ.

c. The diffuser to lover plenum differential pressure reading on an individual )et pump varies from the mean of all )et pump differenti a.'

pressures by more than 10Z.

BFH 3.6/4.6-11 Unit 1 AMENOMENr N. Z g 8 p~GC

0 SAPBTY I INIT f INITIN3 SAPETY SYSTEN SBTTIHQ 1.2 Reactor Coolant S stea Inte rlt 2.2 Reactor Coolant S tea Inte rlt Applies to llalts on reactor coolant Applies to trip settings of thc systea pressure. instruecnts and devices which are provided to prevent the reactor systea safety lialts fraa being exceeded.

O~b8cl 1v8 o~h ective To establish a ligilt below which To define the level of the the integrity of the reactor process variables at which coolant systea is not threatened autccaatic protective action due to an overpressure condition. is initiated to prevent the pressure safety limit free "

being exceeded.

S ecificatlons A. The pressure at the lowest point The limiting safety systea of the reactor vessel shall not settings shall be as specified exceed 1,375 psig whenever below:

irradiated fuel is in the Liwiting Safety reactor vessel. rotcctlve Action S tea Settin SR 2'f.3l

h. Nuclear systea 1.105 psig +

relief valves sg, sl open nuclear (4 valves) systca pressure Cgz~gc 4 gC 4 I S TS, 3.o 1,115 psig +

33.5 osl (4 valves)

~

1.125 pslg +

83.8 -k+ psl (5 valves)

B. Scraa--nuclear <1,055 psig systen high pressure BFN 1.2/2.2-1 unit l

S UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP

0 OEt; 0 V 1SS4

2. Anytime irradiated fuel is in 2. Pith the air sampling the reactor vessel and reactor system inoperable, grab coolant temperature is above samples shall be obtained 212'F, both the sump and air and analyzed at least sampling systems shall be once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

OPERABLE. From and after the date that one of these systems is made or found to be inoperable for any reason, the reactor may remain in operation during the succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the sump system or 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for 5+8 ~ST(FICA7 /QPJ ~Q the air sampling system. CPA+G:E-svo BFN )'sl-s gc/g

+ 3.0.5 The air sampling system may be removed from service for a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for calibration, function testing, and maintenance vithout providing a temporary monitor.

3. If the condition in 1 or 2 above cannot be met, an orderly shutdovn shall be initiated and the reactor shall be placed in the COLD SHUTDOWN COlQITIOK vithin 24 hours. sp s..~ l tely one-half o~

l?,he al relief val s sh 11 be . ch-cheched r When ore than one relief repla d vith a valve is kaovn to be failed p,Z bench-chewed valv each p<glot4 an orderly shutdovn shall b operating cyc JQ.1 13 p initiate e react r valves vill have h!Ien depress o lyas 10 chere~or replace~on

~ ig vithin ours. e the compMtion of every c ar ot req ed to bc in COLD L,h goo&5 lg2Q SHUTDOWN 2. In accordance vith /,Z.

5g.4'f.3.> Specification .O.tR

)),ca),;l Q each relief valve shall be aanually opened unti 7rapos~ c c Qp3 hble. ha co tic m tora sas4~~ o trc of the alv dicate team i flo ng om thc valve.

6/4.6-10 AMENDMENT 10. 2 29 BFR 3 Fia=-~OF~

I HOY 18 1S88

~r ~ ~

3 4

Tho te 'ty of che r eh on be ont o ly to v es rpo atQxg the bellove design are install 4, leaa one r ief alv e di emb d azicl act ea the e.

3.6A. &~max

1. Whenever the reactor is in the 1. Rxenever there is STOUP oz EHf modes, all Jet recirculation flov vith pampa ahall be OPELQKZ. the reactor in the it ia determined that a get STQCUP or RON modes pap is inoperable~ or if tvo vith both recirculation or more )et pump flov instrument poaye ramduS, get pmnp failures occur end cannot be operability shall be corrected vithin 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, sn checJcack daily by orderly shntdovn shall be initiated and the reactor ahall veri~ that the follcndxw conditions

[- CanamOI vithin Zi ~.

be ekan~rn in the COLD SKFRtNN do not occur simnltaneoasly1

a. The tvo recirculation loops have a flov imbalance of LSZ or more vhen the pampa QQ Qug4s ls qgL >0M are operated at the C4c.~q

• Q,Phd <gP~

b.

same speed+

~ indicated value 2 4 2, a e,k P -1 ps.

of core flov rate varies from the value derived from loop flov measurements by more than 10K.

c~ The diffnaer to lover plenum differential pressure readfilg on an individuaJ, p1mep varies from the mean of all )et pump differential pressures by more than 10".

3. h/4. 6-11 AMENDMENT NO 15 4 Vn't "

SAFETY LIMIT LINITING SAFETY SYSTEN SETTING l.2 Reactor Coolant S stem Inte rit 2.2 Reactor Coolant S tern Inte rit Applies to limits on reactor coolant Applies to trip settings of the system instruments and devices which are provided to prevent the reactor system safety limits prcssure'~e frcci being exceeded.

ective O~e votive To establish a limit below which To define the level of the the integrity of the reactor process variables at which coolant system is not threatened automatic protective action due to an overpressure condition. is initiated to prevent the pressure safety limit from being exceeded..

S ecifications S cifications A. The pressure at the lowest point The limiting safety system of the reactor vessel shall not settings shall be as specified exceed 1,375 psig whenever irradiated fuel is in the below'ijiiting Safety reactor vessel. protective Action S stem Settin 5R 9.0,9./

h. Nuclear system 1.105 psig +

relief valves 93 psi open nuclear (1 valves) system pressure

.115 psig +

SEE'Q5TIF'Ic/TIoAJ F'ag - 3i.S (i valves)

CPANg gee ~O gyral i~g Z ~

1,125 psig +

si (5 valves)

B. Scram- nuclear <1,055 psig system high pressure BPN 1. 2/2. 2-1 PAGE Unit 2

UNIT 3 CURRENT TECHNICAL SP ECIF ICATION MARKUP PAGE~OF~

0 5

DEt' 7 1994

~ 6.C 4.6.C

2. Anytime irradiated fuel is in 2. With the air sampling the reactor vessel and reactor system inoperable, grab coolant temperature is above samples shall be 212'F, both the sump and air obtained and analyted sampling'systems shall be at least once every 24 OPERABLE'rom and after the hours.

date that one of these systems is made or found to be inoperable for any reason, the reactor may remain in operation during the succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the ~~ X~564ie4on 0 ~ chases sump system or 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for + BIN jsTs 3'.q.y the air sampling system. p3.V.s'he air sampling system may be removed from service for a period of 4 hours for calibration, function testing, and maintenance without providing a temporary monitor.

3. If the condition in 1 or 2 above cannot be met, an orderly shutdown shall be initiated and the reactor shall be placed in the COLD SHUTDOWN CONDITION within 24 hours. sg P.f>.

'in M>

jn jIhfS o

proximately onc-half 11 relief val s shal e bench-chec d

1. When than on relief or repl d vt,th a valve is known to be failed, bench-ch eked vc, an orderly shutdam shall b ach o r n c cle initiate d the reactor hll 13 ~alves vill have depressurite o lcaa 0 be checked r sx v thin ~ e repla d upon t LR e c s a n re i ed complet of eve t e 0 ERAB i th CO second cycle.

CON TIO sR z.s.s.c 2 accordance with If'n od<$ lp X43 Specification each relief valve shall

+l jCR bIll ProPOSC Jj HO< be manual t thermoco o ed es and

~ SP.3. la.> aco tic monito downs earn of the alve indicat steam is the valve BFH 3. 6/4. 6-10 AMENVHrrNIL X 86 Unit 3 Po.GE~O'~

0 SPecif)cafjnr) 3.Q.3'OV 18 t988 Q5 3. Th in egrity of the r ie val e b 11 vs

~ al bc ont nu usl on ore vh alv s inc rpo ati e ellovs de ign rc ns al d.

4. At eas one rel ef v lve s ll d i di pcc ed ass ach ble 0 cra ing cyc ~

3.6.E. Jet~ups E. J~e

1. Whenever the reactor is in the 1. Whenever there is STARTUP or RUH modes, all jet recirculation flov vith pumps shall be OPERABLE. If the reactor in the it is dctermincd that a jet STARTUP or RUH modes pump is IHOPERABLE, or if tvo vith both recirculation or more jet pump flov instrument pumps running, jet pump failures occur and cannot be operability shall be corrected vithin 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, an checked daily by

. orderly shutdown shall be . verifying that the initiated and thc reactor shall folloving conditions be placed in the COLD SHUTDOWN do not occur COHDITIOH vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. simultaneously:

a. The tvo rccirculatio loops have a flov imbalance of 15X or more vhen the pumps 5'ee arc operated at the Tus&ceh>>n J>>~ same speed>>

c4ngc's 4 BcN 7srs g.q.2

b. The indicated value 5<fpuw p g of core flov rate varies 'from the value derived from loop flov measurc-mcnts by more than 1OX.

c. The diffuser to lover plenum differential pressure reading on an individual jet pump varies from the mean of all jet pump differential pressures by more than 10X.

BFH Unit 3 3.6/4.6-11 AMENOMBfrN. I 29

5fec)@ca an 3'.< 3 1.2 2.2 hpplles to liaits on reactor coolant Applies to trip settings of thc systea prcssure. instruments and devices vhich are provided to prevent thc reactor systca safety liaits froa being excccded.

To establish a liait belov vhich To define thc level of thc process variables at vhich thc integrity of thc reactor coolant systea ls not thrcatencd automatic protective action due to an ovcrpressure condition. is initiated to prcvcnt thc pressure safety lialt froa being exceeded.

h. The prcssure at thc lovcst point The liaiting safety systea of the reactor vessel shall not ~ ettings ahall bc as specified exceed 1,375 psig vhenevcr bclov!

irradiated fuel is ln thc reactor vcsselo 5R S4, .I J. Nuclear systea 1 105 pslg g relief valves 33,xM psi open nuclear (4 valves)

"

systea pressure 115 craig g m psl

'f S

4 valves)

Scc SLL5+

s gasw .g ~ psi 1 125 (5

psig g valves) 4s f5 '2eg B. Scraa nuclear g1,055 psig systea high prcssure BPK 1.2/2.2-1

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.3 - SAFETY/RELIEF VALVES ADMINISTRATIVE A1 Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

The Frequency for proposed SR 3.4.3. 1 (CTS 4.6.0.1) has been changed from "each operating cycle" to "18 months." Since an operating cycle is 18 months these are equivalent. The Frequency for proposed SR 3.4.3.2 (CTS 4.6.0.2) has been changed from "In accordance with Specification 1.0 HH" to "18 months." Since the Inservice Testing Program (1.0.HH) frequency is 18 months these are equivalent. As such, these changes are considered administrative.

A3 The proposed change adds a note that states that the Surveillance is not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test. Plant startup is allowed prior to performing this test because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASHE code requirements, prior to valve installation. As such, the addition of the note is considered administrative.

A4 CTS 3.6.D. 1 requires an orderly shutdown when more than one relief valve is known to have failed. Therefore, the CTS allows unlimited operation with one S/RV inoperable. BFN has 13'/RVs, therefore, 12 are required OPERABLE at all times. LCO 3.4.3 requires 12 to be OPERABLE and shutdown if one of the 12 required S/RVs is inoperable. As such, the two Specifications are equivalent and this change in presentation is considered administrative.

BFN-UNITS 1, 2, 5. 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.3 - SAFETY/RELIEF VALVES A5 BFN CTS 4.6.0.3 is only applicable to three stage Target Rock S/RVs.

Only the two stage Target Rock S/RVs are'nstalled and authorized for use in BFN Unit 2. The three stage design is obsolete and is no longer supported at BFN. Since this Surveillance Requirement is no longer applicable to the BFN S/RV design, the deletion of this requirement is considered administrative.

TECHNICAL CHANGE - MORE RESTRICTIVE Ml Ah'additional requirement is being added that requires the plant to be in MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This change is more restrictive because't stipulates that the reactor shutdown be completed much earlier than would be required by the existing specifications (CTS 3.6.D. 1). CTS requires a shutdown to MODE 4 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> but does not stipulate how quickly MODE 3 must be reached. Reference Comment L2 which addresses the less restrictive change of be in MODE 4 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> rather than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

TECHNICAL CHANGE - LESS RESTRICTIVE "Generic" LAl The details relating to methods of performing Surveillances have been relocated to the Bases or procedures. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in Chapter 5 of the Technical Specifications. Changes to the procedures will be controlled by the licensee controlled programs.

LA2 This Surveillance Requirement has been relocated to plant procedures since the requirement does not directly relate to S/RV operability.

This is strictly a preventive maintenance requirement.

0 Pr. "- QF BFN-UNITS I, 2, 5 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.3 - SAFETY/RELIEF YALVES "Specific" Ll The allowed lift setpoint tolerance has been increased from 1% to 3%

based on incorporation of this larger setpoint tolerance in the BFN reload licensing analysis for each Unit prior to ISTS implementation.

The larger setpoint tolerance has already been incorporated into the Unit 2 reload analysis and will be incorporated into the Unit 3 reload analysis for the next cycle (Spring 1997). In addition, when the setpoints are verified, they are still required to be reset to 1%

(proposed SR 3.4.3. 1). Thus, since the analysis still ensure that all limits are maintained even with the expanded tolerance, this change is considered acceptable. This change is also consistent with the BWR Standard Technical Specifications, NUREG 1433.

L2 The time to reach NODE 4 (reactor depressurized to < 105 psig, Cold Shutdown) has been extended from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This provides the necessary time to shut down and cool down the plant in a controlled and orderly manner that is within the capabilities of the unit, assuming the minimum required equipment is OPERABLE. This extra time reduces the potential for a unit upset that could challenge safety systems. In addition, a new (more restrictive) requirement to be in NODE 3 (Hot Shutdown) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been added (Reference Comment M4 above).

These times are consistent with the BWR Standard Technical Specifications, NUREG 1433.

0 BFN-UNITS 1, 2, L 3 Revision 0

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

0 SPec ikcrc ]ion (gi (g es Lz w3 crab; sea.v.e l

1. a. Any time irradiated l. Reactor coolant fuel is in the system leakage shall 3 pp)> I gg reactor vessel and be checked t e reactor coolant temperature is above Jal 8 ai s r ore li

~ 3.R.9.k 212 e into the primary containment

~thours.

least once per irom unidentified sources shall not exceed In add tion, t e total reactor Mo 3,4,q.c. coolant system leakage into the primary containment shall not exceed

b. haytime the reactor is in RUlf NODE, reactor coolant Qo 3,Q,Q,Q leakage into the primary containment from unidentified sources shall not increase by more than 2 gpm averaged Qi'+in pJlCvia~

~ axe~ay 24-hour period in which the'eactor ia in the RUE NODS cep as e ne n 3.6.C.l.c below.

C~ During the first 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in the RUE NODE following LCo Z.g,q g STAEHJP, an increase in reactor coolant leakage into the primary containment of.,>2 gpa is acceptable as long as the requirements of 3.6.C.l.a are met.

Rl kg gmggq ~

BFH 3.6/4.6-9 ANENOMNr N0. Ig 7 Unit 1 i~AGE~~>> ~

8PECi K< C $ og Q( QEC 07 19S4

2. Anytime irradiated fuel is in 2 With the air sampling the reactor vessel and reactor system inoperable, grab coolant temperature is above samples shall be 212'F, both the sump and air obtained and analyzed sampling systems shall be at least once every 24 OPERABLE. From and after the hours.

date that one of these systems is made or found to be inoperable for any reason, the ~<<3'us4g;~hon P, ~+~

reactor may remain in operation during the-succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

~ BP'r4 1575 Z,q,q for the sump system or 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for the air sampling system.

The air sampling system may be removed from service for a L3 period of 4 hours for d JF<guircd'can a,g calibration, function testing, and maintenance without Ad~ R+o~- providing a temporary monitor. Add P" once'A'on oP

+ 'A gCQHl< Rch'on L ml g~~~ 8 3. If the condition'n 1 or 2 above cannot be met, an orderly shutdown shall be initiated and the reactor shall be placed 'n

~ "~4'+W th COLD SHUTDOWN CONDITION within hours. 4.6.D 3.6.D hRlig Q l. Approximately one-half of all relief valves

1. When more than onc relief valve shall be bench-checked is known to bc failed, an or replaced with a orderly shutdown shall bc bench-checked valve initiated and thc reactor each operating cycle.

depressurized to less than 105 All 13 valves will have psig within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The been checked or relief ~alves are not required replaced upon the to be OPERABLE in the COLD completion of every SHPTDO~. ONDITIOH. second cycle.

2. In accordance with fD 8I-iv

+ ca Specification 1.0.MM,

~ e pl each relief valve shall R(g be manually opened until thermocouples and acoustic monitors downstream of the valve indicate steam is loving from the valve.

BFN Unit 1 3.6/4.6-10 AMENDMENT NL R l

UNIT 2 CURRENT TECHNICAL SPECIFICATION IVIARKUP PAGE OF~

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S ~'4 C~4;o~ S.V.9 DEC 0 '? 199'I 2 ~ Anytime irradiated fuel is in 2. Vith the air sampling the reactor vessel and reactor system inoperable, grab coolant teaperature is above samples shall be. obtained 212 F, both the sump and air and analyzed at least sampling systems shall be once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

OPERABLE. From and after the date that one of these systems is made or found to bc inoperable for any reason, the reactor may reasfn in S~>~S 7.]Rmnoe Fog operation during the ~"" ~~S~ ar Is~~.yS succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the <~IS S'~clod sump system or 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for the air sampling system.

The air sampling system may be removed from service for a L3 period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for calibration, function testing, Adct. and maintenance vithout Dc7'Iod P, rovidi a tea ora monitor. ]V(d eepu,~& A 4o~ B.Z P jeep~'~

ego~ 3. If the condition in 1 or 2 AdcP 2M D above cannot be metD L11

,~<<~ c. orderly shutdovn shall be Ac7104 Q (Igf Co<

)

JiSr~ initiated and the reactor shall be placed i the COLD WK CONDITION vithfn 4.6.D ours ~

Po7 5//~why 1. Appro~tely one-half of 3.6.D 4,oD3plZ3o&

JQ gong and all relief valves shall be bench-checked or When more than one rcl e replaced vith a valve is knovn to be failed, bench-checked valve each an orderly shutdovn shall bc operating, cycle. All 13 initiated and the reactor valves vill have been depressurfred to less than 105 checked or replaced upon psig vf@EX~4 hours The the completion of every relief valves are not required second cycle.

to be OPERABLE in the COLD SHUTDOW COHDITIOlf In accordance vith f

Speci ication 1.0.lS, each relief valve shall

~> 3~S7 I/iCA77ohJ p'o~ be manually opened until CAAo1665 7o g/Q I~7~g qg theraocouples and

~N <<<~ 5'Cc77og acoustic monitors dovnstream of the valve fndfcate steam is floving from the valve.

BFH 3.6/4.6-10 hMENDMBIT N. 2 29 Unit 2  :=A!."." 3

UNIT 3 CURRENT TECHNICAI SPECIFICATION MARKUP PAGE OF

SA c.i<i 0'o AUG 26 1987

~~< 2+3 SR 3,~.w. t

l. a. Any time irradiated 1. Reactor coolant system lcakagc shall R ppl ifctfy,'tip fuel is in the reactor vessel and bc checked y t reactor coolant sum st an ai sam li temperature is above re ord 212 F e c r coo ant at east once per ge into thc hours.

/CO 3 primary containment from unidentified sources shall not 5 In addition, the total reactor coolant system Lco gg g. leakage into the primary containment shall not exceed

b. Anytime the reactor is in RUB mode, reactor coolant leakage into the primary containment from unidentified sources shall not increase by y)s&>n %AC more than 2 gpm avcragcd FfC Js04LS in vhich the reactor is in the RUE mode cpt as c c 3.6.C.l.c below.

Co During the first 24 hour in'he RUN mode follov STARTllP, an increase in reactor coolant leakage into thc primary containment of >2 gye is acceptable as long..as the requirements of 3$%1.a"are met.

Pl ) Rdd 4C0 3.q,'I,a 3.6/4.6-9 NatmNr gO. g o 8 BPS Unit 3 PAGE 3

DEC 0 7'1994 20 Anytime irradiated fuel is in 2. With the air sampliag thc reactor vessel and reactor system inoperable, grab coolant temperature is above samples shall bc 212'F, both the sump and air obtained and analyscd sampling systens shall be at least once every 24 OPERABLE. From and after the hours.

date that onc of these systems is made or found to be inoperable for any reason, the reactor may remain in operation during the succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the sump system or 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for.

5 SLeSAF'eQon &4 Qhagu + 8 P'nl Z.S TS Z.q,5 the air sampling system. ~ +hiSSccgon The air sampliag system may be removed from service for a period of 4 hours for calibration, function testing, and maintenance vithout R>D /I@ion A rovidiag a temporary monitor.

D kQLhiF< Qt'.tl4~ Bo2

+ Requircst If the condition in 1 or 2 Avion "~~ ><~ Qnn(i'h'on oF 8,1 above cannot be met, an orderly shutdown shall be Rch'on ~ )

Ac<i'aN C initiated and the reactor (t s4 Co~d4'i~) shall be placed in thc COLD S CONDITIO vithin 4.6 D.

ours 3.6.D.

34

~

l SNYPo~4 fnndifjoee Ift

1. hpproxijnately one-halt of all relief valves t

/P honte md shall be bench-checked When more than re c or replaced with a valve is known to be failed, benc~hecked valve an orderly shutdown shall be each operating cycle.

initiated and the reactor hll 13 valves vill hav depressurised to less than 105 been checked or psig within 24" hours. The replaced upon the relimf snLLyes are not required completion of every to be OPERABLE in the COLD secoad cycle.

SHUT1XNN CONDITION.

2. Ia accordaace vith Specificatioa 1.0.IR, each relief valve shall F44 ipse'cc4Ãon A~ ~+pcs be manually opened W Bkd %575 3.9,'3 xn until thermocouples aad W>s',ekion acoustic monitors downstream of the valve indicate steam is flowing from the valve BFN unit 3 3.6/4.6-10 NENMBlTNL I 86 q IP

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.4 - RCS OPERATIONAL LEAKAGE ADMINISTRATIVE A1 Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

The total LEAKAGE limit applies at any moment, to the previous 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (not any future or past 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period). This results in a "rolling average" covering "any. 24-hour period." Therefore, changing "any" to "the previous" does not change any intent. In addition, the current provision (CTS 3.6.C. l.c), which allows an increase in reactor coolant leakage into the primary containment of )2 gpm during the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in the RUN mode following STARTUP as long as unidentified leakage and total leakage limits are not exceeded, is encompassed by proposed LCO 3.4.4.d which allows the same. LCO 3.4.4.d is worded differently (i.e.,

a 2 gpm increase in unidentified leakage within the previous 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period in MODE 1) but means the same. Since there is no "previous" 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period until being in MODE 1 for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, this limit does not apply for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. These are editorial changes only and as such are considered administrative.

TECHNICAL CHANGE - MORE RESTRICTIVE A new requirement has been added to preclude pressure boundary LEAKAGE.

An applicable ACTION has also been added. This is an additional restriction on plant operation.

BFN-UNITS 1, 2, 5 3 Revision 0

0 JUSTIFICATION FOR CHANGES BFN ISTS 3.4.4 - RCS OPERATIONAL LEAKAGE CTS 3.6.C.3 requires an orderly shutdown be initiated and the reactor to be in the COLD SHUTDOWN CONDITION within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when certain conditions can not be met. Proposed Action C will require the plant be in MODE 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The addition of this intermediate step to the COLD SHUTDOWN CONDITION is considerqd more restrictive since CTS does not require any action to have taken place within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. 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 safety systems.

M3 The proposed applicability of MODES 1, 2 and 3 is more restrictive than CTS 3.6.C. l.a applicability of "Any time irradiated fuel is in the reactor vessel and reactor coolant temperature is above 212'F." The Startup Mode will now include the mode switch position of "Refuel" when the head bolts are fully tensioned. The change eliminates the potential to interpret certain plant conditions such that no MODE, or a less restrictive MODE, would exist. Currently, CTS 1.0.H allows the plant to be considered in the SHUTDOWN CONDITION and in the Shutdown Mode with the mode switch in the Refuel position (and other positions are allowed while in the Shutdown Mode) as permitted by notes to that definition.

The allowance to place the Mode Switch in other positions has been moved to Section 3. 10, Special Operations and Section 3.3.2. 1, Control Rod Block Instrumentation. Any technical changes to these allowances will be discussed in the Justification for Changes to these Sections.

TECHNICAL CHANGE - LESS RESTRICTIVE "Generic" LAl Details of the methods for performing this Surveillance are relocated to the Bases and procedures. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in Chapter 5 of the Technical Specifications. Changes to the procedures will be controlled by the licensee controlled programs.

PAGE~Or~

BFN-UNITS 1, 2, 5 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.4 - RCS OPERATIONAL LEAKAGE "Specific" Ll The total LEAKAGE allowed has been increased to 30 gpm. No applicable safety analysis assumes the total LEAKAGE limit. The limit considers RCS inventory makeup and drywell floor drain capacity. The new limit of 30 gpm is well within the capacity of the Control Rod Drive System pump and the RCIC System, and is well below the capacity of one drywell equipment drain or floor drain pump, which is used to pump the water out of the collecting sump. The collecting sumps can also accommodate this small additional leakage rate.

L2 The Frequency has been changed from 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, consistent with the allowance in Generic Letter 88-01, Supplement 1. The supplement allows the Frequency to be extended to shiftly, not to exceed 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Browns Ferry Technical Specifications currently define the frequency of shiftly as 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, thus, this Frequency is adjusted to coincide with this.

CTS do not provide a period of time to reduce leakage prior to initiating an orderly shutdown. Proposed ACTIONS A and B allow 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to reduce LEAKAGE within limits prior to initiating a shutdown. This is reasonable since the total leakage limits are conservatively below the LEAKAGE that would constitute a critical crack size. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> completion time for ACTION B is reasonable to properly verify the source

. of unidentified leakage before the reactor must be shutdown without unduly jeopardizing plant safety. The proposed changes are consistent with the BWR/4 Standard Technical Specifications, NUREG 1433.

L4 The time allowed to shutdown the plant when the required actions are not met has been changed from "in the COLD SHUTDOWN CONDITION within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />" to in MODE 3 (Hot Shutdown) in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 (Cold Shutdown) within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The proposed 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. The additional 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed to reach Mode 4 is offset by the safety benefit of being subcritical (MODE 3) in a shorter required time.

PAQF~OF~

0 BFN-UNITS 1, 2, & 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.4 - RCS OPERATIONAL LEAKAGE L5 Proposed LCO 3.4.4, RCS Operational Leakage, will add an alternative to existing requirement in Specifications 3.6.C.l and 3.6.C.3 that a reactor shutdown be initiated if unidentified leakage increases at a rate of more than 2 gpm within a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. Under proposed Required Action B.2, unidentified leakage that increases at a rate of more than 2 gpm within a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period will not require initiation of a reactor shutdown if it can be determined within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> that the source of the unidentified leakage is not 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. This alternative Required Action is acceptable because the low limit on the rate of increase of unidentified leakage was established as a method for early identification of Intergranular Stress Corrosion Cracking (IGSCC) in Type 304 and Type 316 austenitic stainless steel piping. IGSCC produces tight cracks and the small flow increase limit is capable of providing an early warning of such deterioration. Verification that the source of leakage is not Type 304 and Type 316 austenitic stainless steel eliminates IGSCC as a cause of leak. This significantly reduces concerns about crack instability and the rapid failure in the RCS boundary. Also, the unidentified LEAKAGE limit is still being maintained and will continue to limit the maximum unidentified LEAKAGE allowed. This change is consistent with NUREG-1433.

BFN-UNITS 1, 2, 5 3 Revision 0

CURRENT TECHNI AL SPECIFICATION MARKUP

~ 8- c dry I~ a y3 QKC 07 1994 Al Anytime irradiated fuel is in 2. With the air sampling the reactor vessel and reactor Zeu w system inoperable, grab coolant tempera e is above ,

Rcg'on samples shall be 12'F, oth the sump and air obtained and analyze 4Co 3.9e4 sampling systems shall be OPERABLE. From and after the 8.I at least hours.

once every ~

/2 date that one of these systems is made or found to be QCT]ddt inoperable for any reason, the r90 B reactor may remain in operation during the succeeding 24 urs $ 6 QQq5 Pr'~ca for the sump system or ~~emu's hfoQ W for the air sampling system., I ifcHonS g8 I e air s pling system ay e r oved fr m serv ce for a per d of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or cali ation, funct n tes ng, and ma ntenan e vit ut provi a tern ora monit r

3. If the condition in 1 or Q2 AhogS above cannot be met, an orderly shutdown shall be initiated and i<

m tiorA r~~ ~iT~

C+o l2howrc one the reactor shall be placed in the COLD SHUTDOWN CONDITION vithin h s. 4.6.D 3~ Ll

.e.D l. Approximately one-hal f

of all relief valves

1. When more than one relief valve shall be bench-checked is known to be failed, an or replaced vith a orderly shutdown shall be bench-checked valve initiated and the reactor each operating cycle.

dcprcssurizcd to less than 105 All 13 valves vill have psig vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The been checked or relief valves are not required replaced upon the to bc OPERABLE in thc COLD completion of every SHUTDOWN.~NDITIQN. second cycle.

2. In accordance vith See Su~gp;~ye Specification 1.0.NM, each relief valve shall C4lnoIt.5 ~ 8F:~ be manually opened bt Bg5 5qcg until thermocouples and og acoustic monitors downstream of the valve indicate steam is flowing from the valve.

BFN 3.6/4.6-10 AMENDMNTNO. 2 Z3 Unit 1 OF~

S IAblE 3.2.

51RtNENIAI ION IIAI INN)ISIS i INIO OR tl 5 stas ~2 Set ints A~ctl ne abl fqupa I ent 0 ra n ator se r ctor cool I leakage. LAG lou Inl F

Smp fill I iaer te

>20.1 ain.

2. idered par of swp s tea.

Swp Punp Out Rate i I

c i ain Floor Orain I. Used to ghteoaine unidentifiable lcm Intcgrator A reactor cool anl leakage.

F

2. Considered part of sunup systea.

Swy Fill Rale Iiaer .i Ia.

>"t.S. a Sllql P~1 Out Rate Iiaa:r 8.9 in.

gLo L3 c~

NOISES:

p q,g b Or@sell Air Sampling Oas backgfoungde Pari cu ate I4 C

~ 4 o

I (I) Qicnever a system is required lo be operable, there shall be one operable systco ellher autaaatic or annual, or7 ~<T'f>~

the acliun required in Section 3.6.C.2 shall be laken.

ine the le f lao aanual syst rcby I lee betve swp pwp~tarts is (2) alt ate sy a to de eaka ou because olune o he s u be knae~

ulll be lakcn to conf lra lhc ala and assess t~poss y f (3) titan Ageipt of alum, imacdiate acti Increas+leakage.

BFN Unit I

IABIE 1.2.E IIIRIN ES I %ICY FQt ll tEAII EC N I SR 9.'f 5J Function functional Iesl gg q g Calibralion 5 .5. fnstrmi~nchec

~

F loor Orain Simp F lm Intciirator IQ Air SuplinII Systea SR 3..5.'K PI~ s ~ once th LS

~2 hrS Rale Fino Orain 4'ilg l Rath,1laars ~

le n bicycle ohqel rail c e oo ra n tag c one qar

Are SR y PlORS i,Banal 4 qgly ~.7r)blr q,Z.E.

434 raised i n a.e s.z. ~

4 J)c ~tr~ f$ ~ gag~3 3 ~ ~ nfl)Ainn

~adjt hfe65 DEc, nicAAGA ~

'J N26 l .0 1999 zlda ~

1. Functional tests shall be performed once per

2. Functional tests shall be pcr ormed be ore eac startup with a required frequency not to exceed once per veek.

3. This instrumentation is excepted from the functional test definition.

The functional test vill consist of in)ecting a simulated electrical si al into th surement channel.

4. ested~ing~ogic s tern cti 1 tee~.

L,Ay

5. Refer to Table 4.1.B.

6. e ic sys func onal tee s shaQ incl+e a cail,ibratkqn ange gcr o erati cycle f time clay rc e anKtimerif ncccs1a fo~ propert f th tri s terna The functional test vill consist of verifying continuity across thc inhibit vith a voltohnm)eter.

S. Instrument checks shall bc performed in accordance vith the definition of instrument check (sec Section 1.0, Definitions). hn instrument check is not applicablc to a particular setpoiat, such as Upscale, but. is a qualitative check that the instrument ie behaving and/or indicating in an acceptable manner for the particular plant condition. Instrument check ie included ia this table for convenience and to indicate that an instrument check vill be performed on the instrument. Instrument checks are not required vhen these instruments are not required to be OPERhBLE or are tripped.

9. Calibration frequency shall bc once/year.

10. Deleted

11. Portion of the logic is functionally tested during outage only.

12. The detector vill be inserted during each operatiag cycle* and thc proper amount of travel into the core verified.

13. Functional test vill consist of applyiag simulated inputs (eee note 3) ~

Local alarm lights representing upscale and downscale tripe vill be verified, but no rod block vill be produced at this time. The inoperative trip vill be initiated to produce a rod block (SRM and IRM inoperative also bypassed vith the mode evitch in RUN). The functions that cannot be verified to produce a rod block directly vill be verified during the operating cycle.

BFH 3.2/4.2-59 Unit 1 mml)@sr HS. 1 64 PAGE OF

0 UNIT 2 CURRENT TECHNICAL SP ECIFICATION MARKUP p>aa

DEC 0 7 89'I poJa J,2t 2~ hnytime irradiated fuel is in 4p~:~ 2. With the air sampling the reactor vessel and reactor AC.4-on system inoperable, grab g~l;~l;l,g coolant tern erature is above Sl samples shall be obtained 212'F, both the sump and air and analyze at least L.LO samp ng systems shall bc once every hours.

i 384 OPERABLE. From and after thc a e t at one of these systems is made or found to be P t'Tlob5 inoperable for any reason, the reactor may remain in P+Q operation during the w.p sQ eA succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for thc

~ )4rsoCd system or ~muse for 'ump 8 the air sampling system.

e air sampling syst may be r oved fro scrvicc fo a per d of 4 h urs for cali ation, f ction test and ma tenance thout providi a tcmpor ry monitor.

3~ If the condition in 1 or 2 above cannot be met, an Ae.Tlsg s fgo ~$ pfH79OCdh) Co +I s7lo orderly shutdovn shall bc c+b initiated and the reactor 12, goal J oat shall be placed in e COLD WR COKDITIOI vithin 4.6.D hours.

1. hpproxiaately one-half of

.6.D all relief valves shal) be bench-checked or

1. When morc than onc relief replaced vith a valve is knovn to bc failed, bench-checked valve each an orderly shutdovn shall be operating cycle. hll 13 initiated and the reactor valves vill have been dcpressurired to less than 105 checked or replaced upon 3'~+

psig, vithi~~hours~ The the completion of every relief valves arc not required second cycle.

to be OPERABLZ in the COLD SHUTDOWNÃ COMITIOS. 2. In accordance vith Specification 1,O.W, each relief valve shall be manually opened until

~~TIP ICATJON F'og, thcraocouples and acoustic monitors CJJhuMc ~ epnJ >@~

~43 rm 7R< J ~qy]oQ dovnstream of the valve f

indicate steam is loving from the valve BFH 3.6/4.6-10 AMENMENT NO. Z Z9 Unit 2 PAGE

TASIE 3.2.E INSTRIICNIA IIRT NNIfORS tEAXAGE I ORYKtt System 2 Set ints Action qu pment Ora n I. se o erm ne dent I f e Fl ntegrator A r tor coolant leak@a. gAs Swp ll Rate 2. Cons red part of swpgystea.

TIa>>r >20.1 min.

Swp.Pmp t Rate Tie>>r <13.1 min F loor Orain I. Used to determine unidentifiable Floe Integrator reactor coolant leakage.

Smp Fill Rate 2. Considered part of swp system.

1 Ia>>r >80.i in Smp Pmp Out Rate Tie>>r  %.9 sin.

L<0 LE or Or@el I Air Sanpl ing Gas and 3 Xgverage Part culate background W

hl NOTES:

lu I

Cl (I) lkenever a system'Is required to be operable, there shall be one operable system either autanatlc or manual, or the action required In Section 3.6.C.2 shall be taken.

I rT><<

A

2) An alte te system to determine the leakage f1~~ a manual system <>her~ the tie>> betuee~wp pwp tarts ls amitore~ The tie>> interval <i&i determine the Ieakag~ou because the ~m>> of s vill be knam.

{3) Upo~ecelpt of alarm, <<n>> te action uill be taken to conf I@a the alarm and assess the Ibilit f increaL~leakage.

BFNMlt 2

ININll'I@1 ANO CAI IBNAIION FNE

~ TABIE NCV i.2.~

tN ORAKLL LEAK OEIECIIQI INSIN~IAIION sg 3.4s'. )

Function Floor Oraln Sup Flee Integrator eaealday Air Sanpllng Systea SR 3..5.> 3) A5 once ths L~ (g. ~

te LA4 I~a n S te and ce/ r c ~ Ib9L

'

fiber Oraln c ance/operant cycle g.Aq I

8FNZJnlt 2

W'rg /4 aU qpc /- A'~4 0'2 g 7A r~m,~ > ivy/a <<l ical(o'e 3 a/

am< ~raSs4,>> /4

<o

~~~~~yC < kCA~ZQ ~)~~~~ 'JAN 26 1999 V.S

l. 45. Functional 5$ 3. z. Fir~

tests shall be performed once per P~

20 Functional tests sha e per orme e ore eac startup with a require frequency not to exceed once per week.

3~ This instrumentation is excepted from the functional test definition.

The functional test will consist of injecting a simulated electrical signal into the measur 4~ ed during logic stem functiiial teh4s.

5. Refer to Table 4.1.B og c system unc onal te~ts shall include a o~ibration~nce ~er ope ing cycle functio ng of the o~e delay relays tri stems s

and timers necessary for proper .

7. The functional test will consist of verifying continuity across the inhibit with a volt-ohmmeter.

8. Instrument checks shall be performed in accordance with the definition of instrument check (see Section 1.0, Definitions). An instrument check is not applicable to a particular setpoint, such as Upscale, but is a qualitative check that the instrument is behaving and/or indicating in an acceptable manner for the particular plant condition.

Instrument check is included in 'this table for convenience and to indicate that an instrument check will be performed on the instrument.

Instrument checks are not required when these instruments are not required to be OPERABLE or are tripped.

9. Calibration frequency shall be once/year.

10. Deleted Portion of the logic is functionally tested during outage only.

12. The detector will be inserted during each operating cycle and the proper amount of travel into the core verified.

13. Functional test will consist of applying simulated inputs (see note 3). Local alarm lights representing upscale and downscale trips will be verified, but no rod block will be produced at this time. The inoperative trip will be initiated to produce a rod block (SRM and IRK inoperative also bypassed with the mode switch in RUN). The function that cannot be verified to produce a rod block directly will be verified during the operating cycle.

8 /575'3,4r FA ~qz

~<< ~sf'Pcr4i<

~~

BFN 3.2/4.2-59 AMENDMECRV. y jy Unit 2 rAGF ~ ~F~

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP PAGE~OF~

DEC 07 1994

/7lpgg5, \ 2 $ 3 2~ Anytime irradiated fuel is in 2. With the air sampling the reactor vessel and reactor Req~'nd system inoperable, grab coolant tern erat re is above @thon samples shall be t

~ Xg.4 212'F OPERABLE.

oth the sump an air sampling systems shall be From and after the

8. I obtained and analyzed at least hours.,

once every ~12 date that one of these systems is made or found to be

$(. f LOA 5 inoperable for any reason, the P~6 reactor may remain in operation during the Pcc posed blok succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the K Ac.A 5 sump system or i~oars'or 3odAyp

+8 the air sampling system.

Th aa. sam ng sys em ma be rem ved from service or a peri of 4 h s for calib tion, f ction te ting and mai tenance ithout rovidin a tern o moni or.

3~ If the condition in 1 or 2 above cannot be met, an

/}cTlogg orderly shutdown shall be , ~c Abr SlivgeWe CoAoi5ou c+u initiated and the reactor >~ l2.hours and shall be placed in he COLD SKJTDOMN CONDITION within .6.D.

ours e Ll 1. Approximately one-hal

.6 D. of all relief valves shall be bench-checked When more than one relief or replaced with a valve is known to be failed, bench~hecked valve an orderly shutdown shall be each operating cycle.

initiated and the reactor All 13 valves will have depressurised to less than 105 been checked or psig within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The replaced upon the relief'~ves are not required completion of every to be OPERABLE in the COLD second cycle.

SE/TDOMN CONDITION

2. In accordance with Specification 1.0.NM, each relief valve shall

><>>'@AH'o g be manually opened

<Hhsb aP T~ ggA/ lSTS until thermocouples and

+hi5 Se~bo acoustic monitors downstream of the valve indicate steam is flowing from the valvr NeoMENNO. Z 86 BEN Unit 3

3. 6/4. 6-10 i AcE~oF~'

0

'ThNE 3.2.E TI5TRNKNT THAT ICNTTNS LfhlNiif TIITO tl Used to dateaine Identifiable

~iov ~aor reactor

2. Considered ant Toalraoe.

of susp systea.

~4r gO. I ale.

Rap Out Rate llmr ~

i <<T3.4 ale.

Floor Oraln l. Used to date>aine unidentifiable Flee lnte9rator reacior coolant leakage.

LCO Susp Fill ILate 2. Considered part of susp systea.

~'"'~ I S~ Tlmr FLep Out gaQ Tieer LC. >

3i'I.>ibOryuel 1 Alr SapllnII Oa tart cu ate 0'

RIG,:

(1) lt>>never a systea ls rawlred to be terable, Mere sl>>II be one cperable systea eitber autcaatlc or aanual, or the action required le fectlon 3.C.CYshall be tahse.

{2) An a+i 1 terna ed. T ystea Im Ia deterai al uil the Teakyg ~

detaealee as ls a Tat 1 s vo 0>> mba suep susp be s ts ls ~ J

~

1 1

{3 rece of al Ieaedla tlon 1 be to coe the a aed sess poss llltyof late rea sad e A

Q b

hNE .2.f N I 1 Chil Yl F CB- .

floor Orala Sap fly'y4eyrator hir Qep I lac Systea 5g 3.,g. g I2)f5

. liS Kqu t la F ala t c KN-lhlt 8 8

)

CL)

CÃl

~o<S ~

Only Noes l,g~d 0 adcb<SccL i n ~~r aPP/9 +

/MALS

+$

6 lbk q.2.E San+ion p,3

~~s~tg+55y. SPeC'afio~

r<~',. 9..5 9J JAN 26 tS89 Sg, 3ego 5eX day

l. Functional tests shall be performed once per 5 Functional tes s e 1 be performed before each startup with a require frequency not to exceed once per veek.

3. Thiy instrumentation ie excepted from the functional test definition.

The functional test vill consist of injecting a simulated electrical signal into the measurement channel

4. Test dur g lo al este.

J R~J

5. Refer to Table 4.1.B.

6. e logic ystem functi 1 tests ha c u e ca b tion ~ce ger op ating c le o time de y rela and t ers n cesar for prier) func oaing o he t e st

7. The functional teat vill consist of verifying continuity across thc inhibit wi,th a volt ohmmeter.

8. Instrument checks shall be performed in accordance with the definition of instrument check (ece Section 1.0, Definitions). An instrument check is not applicable to a pareicular setpoint, such ae Upscale, but is a qualitative check that the instrument is behaving and/or indicating in an acceptable manner for the particular plant condition. Instrument check is included in this table for convenience and to indicate that an instrument check will be performed on the instrument. Instrument checks arc not required when these instruments are not required to bc operable or are tripped.

9. Calibration frequency shall be once/year.

10. (DELETED)

11. Portion of the logic is functionally tested during outage only.

12. Thc detector vill bc inserted during each operating cycle and thc proper amount of travel into the core verified. C

13. Functional test vill consist of applying simulated inputs (seewillnotebc 3).

Local alarm lights representing upscale and downscale trips verified, but no rod block vill be produced at this time. The inoperative trip vill be initiated to produce a rod block (SRM and IRM inoperative also bypassed with thc mode svitch in RUN). The functions that cannot be verified to produce a rod block directly vill be verified during the operating cycle.

See Pug>'iak'on &r <tony S Gpss +5 +

BFN 3 '/4.2-58 AMENOMERF WP. yPg Unit 3 pAGE ~ o"~

0 t ADMINISTRATIVE Al BFN ISTS JUSTIFICATION 3.4.6 -

FOR CHANGES RCS LEAKAGE DETECTION INSTRUMENTATION Reformatting and renumbering are in accordance with the BMR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BMR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

A2 The revised presentation of actions is proposed to explicitly identify that LCO 3;0.3 is required to be entered if all. required RCS leakage monitoring systems are inoperable. This action is consistent with the current requirements and is considered a presentation preference.

Therefore, this change is considered administrative.

A3 The Table format is being deleted. This change is considered a presentation prefer ence. Therefore, this change is considered administrative.

A4 Proposed ACTION B is modified by a note that explicitly states that the provisions of 3.0.4 are not applicable. This explicitly allows a mode change when both the particulate and gaseous primary containment monitoring channels are inoperable. This allowance is provided because, in this Condition, the drywell sump monitoring system will be available to monitor RCS leakage and the compensatory actions for the inoperable system will provide additional indication of RCS leakage. This is an administrative change since existing Technical Specifications do not have an explicit requirement that prohibits entry into a Mode or condition when an LCO required by that Mode or condition is not satisfied. Therefore, CTS allows the actions being permitted by the note being added. This is consistent with NUREG-1433, BFN-UNITS 1, 2, 5 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.5 - RCS LEAKAGE DETECTION INSTRUMENTATION A5 Frequency has been editorially changed from monthly to every 31 days and from every six months to every 184 days. This is an administrative change since these are equivalent time periods.

A6 The current provision (CTS 3.6.C.2, 2nd paragraph) that allows the air sampling system to be removed from service for a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for calibration, functional testing, and maintenance without proyiding a temporary monitor has been eliminated. There is currently no requirement for a monitor for at least 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (CTS 4.6.C.2).

Therefore, the current provision serves no purpose.

TECHNICAL CHANGE - NORE RESTRICTIVE The proposed applicability of NODES 1, 2 and 3 is more restrictive than CTS 3.6.C. l.a applicability of "Any time irradiated fuel is in the reactor vessel and reactor coolant temperature is above 212'F." The Startup Node will now include the mode switch position of "Refuel" when the head bolts are fully tensioned. The change eliminates the potential to interpret certain plant conditions such that no MODE, or a less restrictive MODE, would exist. Currently, CTS 1.0.H allows the plant to be considered in the SHUTDOWN CONDITION and in the Shutdown Mode with the mode switch in the Refuel position (and other positions are allowed while in the Shutdown Mode) as permitted by notes to that definition.

The allowance to place the Mode Switch in other positions has been moved to Section 3.10, Special Operations and Section 3.3.2.1, Control Rod Block Instrumentation. Any technical changes to these allowances will be discussed in the Justification for Changes to these Sections.

M2 The frequency of grab sampling with the air sampling system inoperable has been increased from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. A grab sample once/12 hours provides adequate information to detect leakage during the extended (See Justification for Change L4) period of time that the air sampling system is allowed to be inoperable.

H3 Not used.

M4 Not used.

H5 The Frequency of the channel check requirement has been changed from every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, consistent with Generic Letter 88-01, Supplement 1 and NUREG-1433. This is an additional restriction on plant

'peration.

BFN-UNITS 1, 2, 8L 3 Revision 0

'

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.5 - RCS LEAKAGE DETECTION INSTRUMENTATION CTS 3.6.C.3 requires an orderly shutdown be initiated and the reactor to be in the COLD SHUTDOWN CONDITION within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when certain conditions can not be met. Proposed Action C will require the plant be in MODE 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The addition of this intermediate step to the COLD SHUTDOWN CONDITION is considered more restrictive since CTS does not require any action to have taken place within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Time is reasonable, based on operating expe} ience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant safety systems.

TECHNICAL CHANGE - LESS RESTRICTIVE "Generic" LA1 The description of an acceptable alternate system to measure leakage has been relocated to the Bases or procedures that support compliance with the limits for RCS Operational Leakage in proposed Specification 3.4.4.

The design features and system operation are also described in the FSAR.

Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in Chapter 5 of the Technical Specifications. Changes to the procedures and FSAR will be controlled by the provisions of 10 CFR 50.59.

LA2 The details relating to the setpoints have been relocated to the procedures. Changes to the procedures will be controlled by the licensee controlled programs.

LA3 The details relating to actions required upon receipt of an alarm have been relocated to procedures. Changes to the procedures will be controlled by the licensee controlled programs.

LA4 Details of the specifics of the functional, calibration, and logic system functional test related to the floor drain sump fill rate and pump out timers has been relocated to procedures since the operability of the system is not dependent upon these timers. Changes to the procedures will be controlled by the licensee controlled programs.

BFN-UNITS 1, 2, 5. 3 Revision 0 PAQE 0F

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.5 - RCS LEAKAGE DETECTION INSTRUMENTATION LA5 The drywell equipment drain sump monitoring system functions to quantify identified leakage. Since the purpose of this specification is to provide early indication of unidentified RCS leakage, the drywell equipment drain sump monitoring system has been relocated to the Bases or procedures that support compliance with the limits for RCS Operational Leakage in proposed Specification 3.4.4. The design features and system operation are also described in'the FSAR. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in Chapter 5 of the Technical Specifications. Changes to the procedures and FSAR will be controlled by the provisions of 10CFR50.59.

TECHNICAL CHANGE - LESS RESTRICTIVE "Specific" Ll The time allowed to shutdown the plant when the required actions are not met has been changed from "in the COLD SHUTDOWN CONDITION within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />" to in MODE 3 (Hot Shutdown) in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 (Cold Shutdown) within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This provides the necessary time to shut down and cool down the plant in a controlled and orderly manner that is within the capabilities of the unit, assuming the minimum required equipment is OPERABLE. This extra time reduces the potential for a unit upset that could challenge safety systems. In addition, a new (more restrictive) requirement to be in MODE 3 (Hot Shutdown) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been added. These times are consistent with the BWR Standard Technical Specifications, NUREG 1433.

L2 This requirement has been deleted. An instrument check would not consistently demonstrate operability since normally the instruments could not be compared to any other instruments, and their reading could be anywhere on scale; thus, observing the meter would provide no valid information as to whether the instrument is OPERABLE. The CHANNEL FUNCTIONAL TEST requirement is the best indicator of OPERABILITY while operating, and this requirement is being maintained. This is also consistent with the BWR Standard Technical Specification, NUREG 1433.

BFN-UNITS 1, 2, & 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.5 - RCS LEAKAGE DETECTION INSTRUMENTATION L3 CTS Table 3.2.E defines the air sampling system as consisting of gas and particulate monitoring channels (i.e., both channels are required OPERABLE for the air sampling system to be considered OPERABLE).

. Proposed LCO 3.4.5.b requires either one channel of the gas or one channel of the particulate monitoring system to be OPERABLE. This is less restrictive than CTS requirements but is acceptable since either channel is capable of indicating increased LEAKAGE rates thaf correlate to radioactivity levels of 3 times average background.

L4 The allowed outage time for the air sampling system has been changed from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 30 days. The 30 day allowed outage time recognizes that at least one other form of leak detection is available (sump monitoring) and takes credit for the increased sampling frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (versus CTS of 24 hrs). This change is consistent with NUREG-1433.

L5 The calibration frequency has been changed once pe} 3 months to once per 18 months. This new Frequency is consistent with BFN setpoint methodology, which considers the magnitude of the equipment drift in the setpoint analysis over an 18 month calibration interval. The primary containment leak detection noble gas and particulate monitor is a digital Eberline continuous air monitor (CAM) which is identical to the building effluent monitors whose calibration frequency is 18 months in accordance with the Offsite Dose Calculation Manual (ODCN) and previously required by Technical Specification Table 4.2.K until these instruments were removed by Amendment No. 216 dated September 22, 1993 (reference TS 301). Excessive calibration can cause damage to the equipment. In addition, plant operations could be impacted while the equipment is removed from service for calibration since it would not be available for leak detection.

BFN-UNITS 1, 2, 5 3 Revision 0 PAGE S GF~

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

clPi' z. V. 4 J N2819%

3.6.8. 4.6.B.

4~ When the reactor is 4~ Whenever the reactor is not not pressurized vith fuel in pressurized vith fuel in the reactor vessel, except the reactor vessel, a during the STARHJP COHDITIOR, ,saaple of the reactor the reactor vater shall be coolant shall be analyzed maintained vithin the at least every 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> folloving liaita. for conductivity, chloride ion content and pH.

ao Conductivity-10 yeho/ca at 25 C

b. Chloride - 0' ppa Sec Sufkif eeHon Ar CJ4nst 5

~'<< >< 8/9 <8 .ta this

c. pH shall be betveen Sec gioa 5.3 and 8.6. llnK A~ sR3'.v,q,l 5~ When the tiae liaita or During guilibriaa pover maxiinm conductivity or operati an iaotop c chloride concentration ana yaia nc liaita are exceeded, an q t t tive ur cata orderly ahutdovn shall be for at 1 aat I 31 -132 initiated iaaediately. The I- I-13 reactor shall be brought to the be perfoza eel~ on a COLD SHUTDOWN CORDITIOR coolan iqaid aaaple.

aa rapidly aa cooldovn rate da) s eraita.

CQuirc A. +s.l LCO 6. Wheneve the reactor ia k4ditional coolant P 9.4 r t cal the ta on activity samples shall be taken concentrations in the reactor vhenever the reactor Ryl'c coolant shall not exceed the ctivi ceeda equilibritm value of 3.2 pCi/ga pre to of dose equivalent I-131. equilibritm concentration specified in 3.6.B.6 c ti re t:

BFR 3 ~ 6/4 ~ 6-7 AMENOMENT Ra. 208 Qnit 1

8

~ '

ympmg N A. + ikey<<,'~

s 4r Cu d.h'hA pcs(od This limit ma bc exceeded for ~ f a. During the ST C HDITIOI a maximum of 4$ hours. During b. ollovi a si fican this activity transient the over e40 iodine concentrations shall not exceed 26 pCi/gm encver e c.,F lloving an,incre c reac or s cr t cal in the equ librium s pcr tc of gas le 1 exceed ng mor 5X its earl 10, 0 pCi/ ec (at the po er op rati n er ste get ai e)ector) cepti n fo thc li siodine vithin a 48-hour period activi limits If the concentratioa in the coolant d. Whenever the equilibrium exceeds 26 pCi/gm, the reactor iodine limit specified

@Tfog shall be shut dovn, and the in 3.6.B.6 is exceeded.

'8 steam line isolation valves The additional coolant liquid samples shall be takea at 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ufik4n tQ Qurg interval or our, or ti LQ, a sta le iodine oncen rati a be ov the limit valu (3.

or be fn NM pC ga) i establ shed.

'I i0hi~ 34 h~rZ Hov cr, a least cons cutive samples shall b akea in al cases. kn isotopic analysis 11 be performed for each sample, and quantitative measuremcnts made to determine the dose equivalent I-131 concentratioa.

7. When there ia no fuel ia the 7. When there is no fuel in reactor vessel, technical the reactor vessel, specification reactor coolant sampling of reactor coolant chemistry limits do not apply. chemistry at technical specification frequency is not required.

• • or the p rpose o this ection sampl frequ cy, a s ficant over chang>> is de ed as a change ceasel 15X f rated p ver ia ess t 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

BFI 3.6/4.6-8 NENOMENT lE 2 9 8 Unit 1 PAGE 3 QF ~

0 INSERT PROPOSED NEW SPECIFICATION 3.4.7 Insert new Specification 3.4.7, Residual Heat Removal System-Hot Shutdown, as shown in the BFN Unit 2 Improved Technical Specifications.

PAGE~OF~

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.7 RHR SHUTDOWN COOLING SYSTEM - HOT SHUTDOWN ECHNIC L C GE - 0 ST IC IV Ml A new Specification is being added requiring two RHR Shutdown Cooling subsystems to be OPERABLE in MODE 3 with reactor steam dome pressure less than the RHR low pressure permissive pressure. Appropriate ACTIONS and a Surveillance Requirement are also added. This is consistent with the BWR Standard Technical Specification, NUREG 1433 and is an additional restriction on plant operation.

BFN-UNITS 1, 2, 5 3 Revision 0

H(

INSERT PROPOSED NEW SPECIFICATION 3.4.8 Insert new Specification 3.4.8, Residual Heat Removal System Cold Shutdown, as shown in the BFN Unit 2 Improved Technical Specifications.

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.8 RHR SHUTDOWN COOLING SYSTBI - COLD SHUTDOWN TECHNICAL CHANGE - ORE ES CTIV Hl A new Specification is being added requiring two RHR Shutdown Cooling subsystems to be OPERABLE in NODE 4. Appropriate ACTIONS and a Surveillance Requirement are also added. This is consistent. with the BWR Standard Technical Specification, NUREG 1433 and is an additional restriction on plant operation.

BFN-UNITS I, 2, 5 3 Revision 0

I 0

UNIT2 CURRENT TECHNICAL SPECIFICATION MARKUP

JUNP,8 tsar 3.6.B. Coo 4.6.B. Coo e t

4. When the reactor is 4. Whenever the reactor is not not pressurized vith fuel in pressurized vith fuel in the reactor vessel, except thc reactor vessel, a during the STARTUP COHDITIOH, sample of the reactor thc reactor vater shall be coolant shall bc analyzed maintained vithin the at le'ast. every 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> folloving limits. for conductivity, chlori ion content and pH.

a. Conductivity-10 pmho/cm at, 25 C

b. Chloride 0.5 ppm 5ec 'X<sf<gi'cbio~ +< +~d~

far <TS 3.C.8 /O'.C.g

c. pH shall bc betveen His S~4<o~

5.3 and 8.6. 4r $ ~3 H.9 I sR 3.'A6 I

5. When thc time limits or 5. Dur quilibrium pover maxilla conductivity or o cratio an iaotop c chloride concentration analysis c limits are exceeded, an itativc me urgents orderly shutdovn shall be for at cast I-13K, I-132 initiated immediately. The -133 and I-1 s reactor shall be brought to be performed on a thc COLD SHUTDOMH COHDITIOH coolan liquid sample.

aa rapidly as cooldovn rate

@CO crmits. H3 9 Joys i ~t 34@ LIj ~

. +'5,

6. Whenever thc reactor 6. Add tional coolant hppl c,. rit ca thc limits on activity samples ahall be taken concentrations in the reactor vhcnever the reactor coolant shall not exceed thc activity exceeds equilibrium value of 3,2 pCi/gm cent of dose equivalent I-131. equilibrium concentration 4.Al specified in '3.6.B.6 one ~f o o c iti are +t:

PAGE BFH 3.6/4+6-7 NENOMENT RtL Z 2g Unit 2

o 0

S cc,S;,4)..~ ~.q(

JUN 8 8 $ 994 (Q

/vog ~P kfNet'4J Ac~

Pygmy>gQ gQ,h c p Cl'lo fJ This limit may be exceeded goal a. During the STARTUP COHDITIOH p 0 for L. of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. During Folloving i4fgnffic this Lctivity transient the pover change +

iodine concentrations shall not exceed 26 pCi/gm enever t e c. olloving an in ease reactor is critical. e i the equilibri eac operated off as level excee ing more t 5X of s year 10,0 pCi/sec (at the pover eration er s steam et Lir e)ector) excep ion for e e uil brium vi in a 48-hour eriod.

ctivit limits If the iodine concentration in the coolant . d. Whenever the equilibrium ETIO+ exceeds 26 pCi/gm, the reactor iodine limit specified 0 Shall be shut dona, and the in 3.6.B.6 is exceeded.

steam line isolation vLlves Pep, The additional coolant liquid A.t samples shall be taken at 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> c W.~ (2. w~ intervals for 48 ours, or unt 1 a sta e iodine c entration belo the limiting va e (357, o~ be I'~ AW yCi/gm is established.

Q ~i& 5$ 4v~ Hovever, least 3 consecutive samples sha 1 cases ka isotopic analysis Shall be performed for each sample, and quantitative measurements made to determine the dose equivalent I-131 concentration.

Shen there is no fuel in the 7. When there is no fuel in the reactor vessel, technical reactor vessel, sampling of specification reactor coolant reactor coolant chemistry at chemistry lild.ts do not apply. technical specification frequency is not required.

For the purpose of this section sampling frequ, a si ficant poser defin as L change e i ceding 1SX of r ed pover in less than 1 hour.

3 '/4.6-8 AMEMOMENt'Mt. M M M PAGE

INSERT PROPOSED NEM SPECIFICATION 3.4.7 Insert new Specification 3.4.7, Residual Heat Removal System-Hot Shutdown, as shown in the BFN Unit 2 Improved Technical Specifications.

PAGE OF

JUSTIFICATiON FOR CHANGES BFN ISTS 3.4.7 RHR SHUTDOWN COOLING SYSTEN - HOT SHUTDOWN T C NIC L C GE - 0 EST IC IV Ml A new Specification is being added requiring two RHR Shutdown Cooling subsystems to be OPERABLE in NODE 3 with reactor steam dome pressure less than the RHR low pressure permissive pressure. Appropriate ACTIONS and a Surveillance Requirement are also added. This is consistent with the BMR Standard Technical Specification, NUREG 1433 and is an additional restriction on plant operation.

BFN-UNITS 1, 2, 5 3 Revision 0

INSERT PROPOSED NEM SPECIFICATION 3.4.8 Insert new Specification 3.4.8, Residual Heat Removal System Cold Shutdown, as shown in the BFN Unit 2 Improved Technical Speci fi cati ons.

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.8 RHR SHUTDOWN COOLING SYSTEN - COLD SHUTDOWN TECHNICAL CHANGE - NORE RESTRIC IVE Hl A new Specification is being added requiring two RHR Shutdown Cooling subsystems to be OPERABLE in NODE 4. Appropriate ACTIONS and a Surveillance Requirement are also added. This is consistent with the BWR Standard Technical Specification, NUREG 1433 and is an additional restriction on plant operation.

BFN-UNITS 1, 2, & 3 Revision 0

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

3.6.B. 4.6.B. C o

4. Mxen thc reactor is 4. Whenever thc reactor is not not pressurized vith fuel in pressurized vith fuel in the reactor vcsscl, except thc reactor vessel, a during the SThRTUP COHDITIOS, sample of the reactor thc reactor vater shall be coolant shall bc analyzed maintained vithin the at least every 96'hours folloving limits. for conductivity, chloride ion content and pH.

a CoILductivity 10 pmho/cm at 25~C

~

b. Chloride - 0.5 ppa ><5+i~i~on Qe Changes

'CI'~ F 4 8/y.C..8;< +h;s Sccdon

c. pH shall be betveen 5.3 and 8.6. Ilfok r 5 3 Q.g, I

5. When the time limits or 5~ During qu libriua povc mm~mL conductivity or peration an sotopic chloride concentration aILa s s2 limits are exceeded, an orderly shutdovn shall be tit tive eas cm ts I- 32, fo at 1 ast -131 initiated immediately. The I-1 I-1 4 s reactor shall bc brought to bc performed oIL a the COLD SHUTDOWN CONDITION coolant 1 quid sample.

as rapidly as cooldovn rate permits. 7$

/5

6. Whenever the I

6~

e '.Ron,l 0 coo ant

8. 1

(

ritic the limits on activity samples shall be taken 3,q,p concentrations in the reactor vhenever the reactor

, coolant shall not cxcecd the activity exceeds 0

(

hyllcrk'IkPOoflibrf a ooloe of 3.2 PCi/ga e en 0 e of dose equivalent I-131. equ br ua concentration specified in 3 o th fo ovi c ii a m BFR 3 '/4 '-7 AMENDMENT NL y8y Unit 3 F~GF~OF

n3.% 6 jets)sg lo gpooS A4 oo gcpw o',CcP j44s'y~S 4w (e J4 A Qhon P This liuent Iaay bc exceeded a. Duri the ST CO ITIOH for a aaxiam of 48 hours. During b. Follovi a signi f ant this activity transient thc pover ec*

iodine concentrations shall not exceed 26 pCi/ eaevcr C~ llovtng an increase reactor s cr tical e the equili ri~

e ore o rate of gas level ceding r than 5 of i s yea y 10, 0 pCi/sec at the vc opcrat oa er s ste 5et air C5 tor) e ion, for c c ilib vithia a 48-hour riod.

a iv ty liaits If the i dine equilibrhm concentra on in the coolant d. Whenever the I+fon exceeds 26 pCi/ga, thc reactor AC),

iodine limit specified

(

8 ahall bc shut down, and the At'H n in 3.6:B.6 is exceeded.

steaa line isolation valves k.l shall be clos The additional coolant liquid samples shall be taken at 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> bligh'on ~ghmr intcrv 1 o 48 ho s, r until stab iod coac trc ioa or be on Q~ b lov liat v e .2 9 lPo'Hlo& 3Q ~Op p /gR) s cata ished Ho ver, t least 3 c cu s ess lbet al cases isotopic analysis be pcrforaed for each saaple, snd quantitative aeasureaents sade to detcraine the dose equivalent I-131 concentration.

7. When there is no fuel in the 7. When there is no fuel in reactor vessel, technical the reactor vessel, specification reactor coolant saapling of reactor coolant cheaistry limits do not apply. cheaistry at technical specification frequency is not required.

g~ >WAXaNon 4 r rC~ '>l'i~ B (~oo,;s C~g For the urpose f this section ssRpl frcqu cyg a s fican power is dc cd as a change ccd 15X f rated vcr jn css 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

BFI 3.6/4.6-8 AMENOMgg ~L Z 81 Unit 3 Gp g 0

INSERT PROPOSED NEW SPECIFICATION 3.4.7 Insert new Specification 3.4.7, Residual Heat Removal System-Hot Shutdown, as shown in the BFN Unit 2 Improved Technical Specifications.

~~CE OF

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.7 RHR SHUTGOMN COOLING SYSTEM - HOT SHUTDOWN EC NICA CHANGE - 0 E EST IC I Ml A new Specification is being added requiring two RHR Shutdown Cooling subsystems to be OPERABLE in MODE 3 with reactor steam dome pressure less than the RHR low pressure permissive pressure. Appropriate ACTIONS and a Surveillance Requirement are also added. This is consistent with the BWR Standard Technical Specification, NUREG 1433 and is an additional restriction on plant operation.

BFN-UNITS I, 2, 5 3 Revision 0

y(

INSERT PROPOSED NEM SPECIFICATION 3.4.8 Insert new Specification 3.4.8, Residual Heat Removal System Cold Shutdown, as shown in the BFN Unit 2 Improved Technical Specifications.

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.8 RHR SHUTDOWN COOLING SYSTEM - COLD SHUTDOWN ECHNICA CHANGE - ORE ESTRIC IVE Ml A new Specification is being added requiring two RHR Shutdown Cooling subsystems to be OPERABLE in MODE 4. Appropriate ACTIONS and a Surveillance Requirement are also added. This is consistent .with the BWR Standard Technical Specification, NUREG 1433 and is an additional restriction on plant operation.

BFN-UNITS 1, 2, 5 3 Revision 0 OF

13USTIFICATION FOR CHANGES BFN ISTS 3.4.6 - RCS SPECIFIC ACTIVITY ADMINISTRATIVE Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical, Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

~ A2 Note is added to the Required Actions for Condition A to indicate that LCO 3.0.4 is not applicable. Entry into the Applicable Modes should not be restricted since the most likely response to the condition is restoration of compliance within the allowed 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. Further, since the LCO limits assure the dose due to a LOCA would be a small fraction of the 10 CFR 100 limit, operation during the allowed time frame would not represent a significant impact to the health and safety of the public. In addition, this allowance is already inherently provided by the words of Specification 4.6.B.6.a, which states that additional samples are required "during startup" when specific activity exceeds the limit. Thus, this change is a presentation preference only and is considered administrative.

A3 Existing Specification 3.6.B.6 requires that if the Dose Equivalent I-131 cannot be restored within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, or if an any time it exceeds 26 pCi/gm, the reactor must be shut down and all main steam lines must be isolated immediately. Proposed LCO 3.4.6, Condition B, allows the alternative of being in MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> under the same conditions. This option is provided for those instances when isolation of main steam lines is not desired (e.g., due to the decay heat loads). In Mode 4, the LCO requirements are no longer applicable. This change is considered administrative because existing 1.0.C. 1 would require that the reactor be placed in Mode 4 within 36 BFN-UNITS 1, 2, 8L 3 Revision 0

~u-;D

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.6 - RCS SPECIFIC ACTIVITY hours if the requirements in CTS 3.6.B.6 could not be met. This change is consistent with NUREG-1433.

TECHNICAL CHANGE - MORE RESTRICTIVE Ml The Applicability has been changed to require the specific activity to be within limits in those conditions which represent a potential for release of significant quantities of radioactive coolant to the environment. Thus, MODE 3 with any steam line not isolated has been added. In addition, MODE 2 with any steam line not isolated has been added in lieu of MODE 2 when the reactor is critical. While this does allow the reactor to be critical with the main steam lines isolated while not requiring the LCO to be met, overall this change is considered more restrictive due to the MODE 2 subcritical and MODE 3 requirements.

In addition, the ACTIONS have been modified to reflect the new Applicability, and an option for exiting the applicable MODES is

- provided for cases where isolation is not desired.

~ e CTS 4.6.B.5 requires sampling reactor coolant to determine specific activity "during equilibrium power operation." Proposed SR 3.4.6.1, which contains proposed requirements for sampling reactor coolant to determine specific activity, is modified by a note that requires this Surveillance to be performed only in MODE 1. This change is slightly more restrictive because sampling will be required whenever the reactor is in MODE 1 and not just when equili6rium conditions have been established. This change is consistent with NUREG-1433.-

M3 The Surveillance Frequency has been changed from monthly to weekly (every 7 days) for consistency with NUREG-1433, Rev. 1. Since Revision 1 to the NUREG deleted the surveillance requirement to verify that reactor coolant gross specific activity is less than or equal to 100/E-bar pCi/gm every 7 days, the reactor coolant specific activity trending interval was decreased to 7 days from 31 days.

TECHNICAL CHANGE - LESS RESTRICTIVE "Generic" LAl CTS 4.6.B.6 contains requirements for reactor coolant and offgas system

~ ~

sampling during startup, following significant power level changes, and

~

BFN-UNITS 1, 2, 8L 3 2 Revision 0 PAGE

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.6 - RCS SPECIFIC ACTIVITY following significant changes in offgas radiation levels. The results of any of these samples are intended to determine if RCS specific activity is exceeding specified limits. Experience has determined that the weekly sampling required by proposed SR 3.4.6.1 and requirements for monitoring main steam line and offgas radiation levels is sufficient to ensure RCS specific activity levels are not exceeded. Therefore, RCS specific activity requirements for sampling stack gas, offgas and main steam line are being relocated to plant procedures and will be controlled in accordance with the licensee controlled programs. In addition, the criteria for when specific activity has been returned to limits (for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or until a stable iodine concentration below the limit has been established with at least 3 consecutive samples being taken in all cases) has been relocated to plant procedures and will be controlled by the licensee controlled programs. The method of determining dose equivalent I-131 (i.e., quantitative measurements of specific isotopes of Iodine), as described in CTS 4.6.8.5, has also been t

relocated to plant procedures. These changes are consistent with NUREG-1433.

"Specific" Ll Pro posed ACTION A allows the LCO limit to be exceeded for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> provided that the specific activity does not exceed 26 pCi/gm. CTS 3.6.B.6 allows the limit to be exceeded during a power transient and limits the time the reactor can be operated, when the LCO RCS Specific Activity limit is exceeded, to less than 5% of its yearly power operation. Generic Letter 85-19, "Reporting Requirements on Primary Coolant Iodine Spikes," states that this limit is not necessary because reactor fuel has improved significantly since this requirement was established, and that proper fuel management by licensees and existing reporting requirements for fuel failures will preclude ever approaching this limit. Removal of this limit is consistent with the BWR/4 Standard Technical Specifications, NUREG-1433, requirements.

L2 CTS 3.6.B.6 requires the reactor to be shut down and the'team line isolation valves to be closed immediately if the iodine concentration exceeds 26 pCi/gm. Proposed ACTION B allows 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to close the isolation valves or to be in Mode 3. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time is reasonable, based on operating experience, to isolate the main steam isola'tion valves, or to achieve the required plant conditions, in an orderly manner and without challenging .plant systems. The less restrictive 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time is consistent with NUREG-1433.

BFN-UNITS 1, 2, & 3 Revision 0 PAGE ~

OF

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP PAG~

Rl SAd> Pi'yn 3.

LI HG COHDITIOHS FOR OPERATIOH SURVEILLAH QUIREMEHTS 3.6 4.6 Applies to the opcrati status Applies t the period of the r actor coolant stem. cxaminatio and test rcquireacnt for the rca tor coolant syst To assure the tegrity and sa To etcrmine the ondition of operation of the eactor coolan the eactor coolan system and systems the o cration of th safety device related to it.

Lgy > q,q 1. The average rate of 1. During heatups and reactor coolant temperature s R i.q.q,) ooldovna the change during normal heatup folloving parameters or cooldowa shall not exceed shall be recorded and 100'P/hr when averaged over ,reactor coolant a one-hour period. temperature determined a minute intervals ti success rea at each given ocation are vi 5 P.

a. Steam Dom Pressure (Convert o upp r vessel r gion temper ure)

Reac r bot om drain tern eratur

c. circul ion lo s A and B

d. React r vcsse bottom head tempera re

e. Rc ctor ve el shell a gaccnt shell flange BFH 3 '/4.6-1 PAGE OF Unit 1

A<

2. Daring all operations vith 2. Reactor vessel metal a critical core, other than temperature at thc for lov-level physics tests, outside surface of thc except vhen the vessel is bottom head in the vented, the reactor vessel vicinity of the control shell and fluid temperatures rod drive housing and shall be at or above the reactor vessel shell temperature of curve 03 of adjacent to shell Figure 3.6-1. flange shall bc ecorde at least every minutes daring inservice bydrostptic or leak testing cn e vessel ressure is > 312 psig.

3. Daring heatup by 3. est ecimcns nonnuclear means, except repre cnt the reactor vhen the vessel is vented vcss, ba e veld and or as indicated in 3.6.k.4, vel heat ffect xone daring cooldovn folloving met 1 be tailed

~'" 'l naclear shutdovn, or in e r actor esse daring lov-level physics a scen to ves 1 tests, the reactor vessel v at the re mi plane temperature shall be at or R2 1 vel. The amber and above the temperatures of carve 0? of Figure 3.6-1 until b e spe in accor ens ance il GE removing tension on the head repo t 1011 . e stud bolts as specified in spe ens hall ce the 3 '.k.5 ~ int t of ESTD 1 -82.

."

- 3 BFS 3.6/4.6-2 Unit 1 IIIENDlNENTHO. 17 0

SEP I3 1995 4~ The beltlinc region of reactor vessel temperatures L~o Z.9Q during inscrvice hydrostatic or leak testing shall be at

) Nl~k, I or above the temperatures shovn on curve 41 of Figure 3.6-1. The applicability of this curve to these tests is SR extended to nonnuclear P~pg~ sw 3'. Q.5.2.

~ ~"fi1, hcatup and ambient loss cooldovn associated vith NoQ Z, these tests only if cooldovn the rates heatup and do not exceed 15 P per S0 z. 9 f. g + 8 a I hour. << ~.s.9.v + Ivy 5'R 3oH.9 1 + No4e

5. Thc reactor vcsscl head 5. When the reactor vessel head sg bolting studs may bc partially bolting studs are tensioned 8.'f.$ .5 tensioned (four sequences of and the reactor is in a cold

/Vinc '2 the seating pass) provided condition, thc reactor vcsscl the studs and flange materials eratur inacdiately are above 70 F. Before belov the head flange shall oading the flanges any more, be thc vcsscl flange and head flange must bc greater than 80 P, and must remain" above 80'P vhilc under full tension.

fiopssrd 4<qgswlcs r

A SRs 3.q,9.5)g+g BFS 3.6/4.6-3 AMENDMBlTNO. 2 P. f Unit 1 PAGE~OF~

S'kc'0'ca on 3.'f.9 SR Z.S8.S+ ~o<X

6. The pump in an idle 6. Prior o r recirculation loop shall not R3 startu o an e

~n gy,q be started unless the recirculation loop, the temperatures of the coolant temperature of the reactor vithin the idle operati i coolant n the o era ecirc at, on loo s are and idle loops shal e vithin 50'F of each other. t en ly o e 7~ The reactor recirculation '

7. Prior to starting a pumps shall not be started recirculation pump, unless the coolant + the reactor coolant L,Co temperatures betveen the temperatures in the dome and the bottom head dome and in the bottom drain are vithin 145 F. head drain shall be compared e o

H3 P'.po'd Acti<~ 34s+;F;wg'<<gg, STARTUP or RUH Mode and

$ r BFA 1575 one recirculation pump 3.q.~ is operating, the diffuser to lover i plenum differential prcssure shall be checked daily and the differential pressure of an individual jet pump .in a looy shall vary from the mean 'ot S~aMi'cz4on @r Cj~~ggc of all Jet pumy 4i BFQ tSvs z differential pressures in that loop by more than 10K.

3.6.F 4.6.F The vith reactor shall not bc operated recirculation loop out

l. Recirculation pump speeds onc shall be checked and logge of service for morc than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. at least once pcr day.

With thc reactor operating, onc recirculation loop is out of if service, the plant shall be placed in a HOT SHUTDOWN COHDITIOH vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless the looy is sooner returned to service.

2~ Folloving onc pump operation, 2. Ho additional surveillance the discharge valve of the lov required.

speed pump may not be opened unless the speed of the faster pump is less thaa 5OX of its rated syeed.

se ~.~.v.v 3~ When the reactor is not in thc 3. Before starting cithcr RUN mode, REACM POWER DPERATIOH recirculation pump vith both recirculation pumps out during REACTOR PO of-service for to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is OPERA yermitted During such interval the oo s rge Sg restart of the recirculation temperature and dome 3Aegi Q pumps is permitted, provided the saturation tempcraturc.

loop discharge temperature is vithin 75'F of the saturatioa BFH 3.6/4.6-12 AMENDMEHT NP. 2yy Unit 1 pAGE~GP~

0 3.6.F 3.9 ~ 9.'9~ A/os 2 temperature of the reactor vessel S~e Y~swkc~g'on @

vater as determined b dome pressure. e total elapsed time kc 9t-Iv f 5 pg p,q, ~

aa ural circulation aad oae pump operation must be no greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The reactor shall not be operated vith both recirculation yumya out-of-service vhile the reactor 'ia in the RUB mode. Folloving a trip of both recirculation pumps vhile in the RUN aode, immediately ate a manual reactor scram.

3.6.G 4.6.G I

The structural integrity of ASME l. Iaserrice inayectioa of MME Code Class 1, 2, and 3 equivalent Code Class 1, Class 2f aad components shall be maintained ia Class 3 components shall be accordance vith Syecificatioa 4.6.G performed ia accordance vith throughout the life of the plant. Section XI of the ASIDE Boile aad Pressure Vessel Code aad a Mith ths structural integrity applicable Addenda as of any ESNE Code Class 1 required by 10 CFR 50, equivalent coaponent, vhich is Section 50.55a(g), except part of th>> primary system, not Mere syecific vritten relic confozILing to the above haa baca graated by HRC requirements, restore the yursuant to 10 CFR 50, structural integrity of the Section 50.55a(g)(6)(i).

affected component to vithin ita limit or maintain the 2. Additioaal inayectiona shall reactor coolant system in be perforaed on certain either a Cold Shutdova circumferential yipe velda to condition or less than 50'F provide additional protection abide the minimum temperature against pipe vhip, vhich required by HUT considerations, could damage auxiliary and until each indicatioa of a control systems.

defect has been investigated and evaluated.

5<< 3KHiAczg'q ~

• 'TS S,S.g/q,g y 3.6/4.6-13 AMENOggPNg, p p6 BFS Unit 1

'8 OF~~

pA

ClS gg JUN 2 8 1994 3.6.B. 4.6.B. C o

1. PRIOR TO ST TUP and 1. Reactor coolant shall be at steaming rates continuously monitored than 0,000 'ess for conductivity except vhen lb/hr, the folloving there is no fuel in the limits sh 1 apply. reactor vessel.

a. Cond ctivity, Whenever the pmh /cm at 25 C 2.0 continuous conductivity monitor is inoperable,

b. oride, ppm 0.1 a sample f reactor coolant hall be analyze for conduct vity every 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> except as liste belov. If the react r is in COLD SHUT OMH COHDITIOH, a s e of reactor co ant shall be lyzed for nductivity every hours.

b. Once a veek the continuous monitor shall be checked vith an in-line flo cell.

This in-line conductivity calibration hall be performed e ery 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> vhen ver the reactor c lant conductiv ty is >1.0 pmho/cm t 25 C.

2. At steaming rates 2. During, star p prior to greater than 100,000 pressurizi the reactor lb/hr, the folloving above atm pheric limits shall apply. pressure measurements of reac r vater quality

a. Conductivity, shall performed to shov pmho/cm at 25 1.0 confo ance vith 3.6.B.1 C

0.2 of li iting conditions.

b. Chloride, ppm BFH 3.6/4.6-5 AMENOMENT RO. 208 Unit 1 FASP / OF~~

DEC 0 7 L994 3.6.B. 4. .B. Coo 3~ ht steaming rates 3. whenever thc reactor greater 100,000 is operating (including lb/hr, thc reactor HOT STAHDBY CORDITIOH) vatcr qua ity may m suremcnts of reactor cxcecd S cification ter quality shall. be 3.6.B.2 nly for the erformed according to time 1 its specified the folloving schedule:

belov. Exceeding these time imits or the follow ng a. Ch1oride ion content max quality limits s all and'H sha be be use for placing measured least once the reactor in the every 96 ours.

CO SHUTDOMR CO ITIOH. b. Chlori e ion conte t shall be

a. Conductivity meas rcd at least time abov eve 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> .

1 pmho/ at 25'C vh ever reactor 2 v ks/year. c ductivity is Maxim Limi t .0 pmho/cm 10 mho/cm at 25'C t 25 C.

c. h sample of actor

b. Chlor de coolant sha bc co entration time measured f pi at a ove 0.2 ppm least onc every 8 2 weeks/year. hours vh ever the Maximum Limit- reactor oolant 0 ~ 5 ppmo conduct ity i,s >1.0 pmho/ at 25 C.

c. The reactor shal be placed in thc S WH COHDITIOR if24-hour pH <5.6 or

>8.6 for a period.

BFH 3.6/4.6-6 AMENOMEHT NIL R 13 Unit 1

~ ~.e.c

'.e,s'ON28m 3.6.B. 4.6.BE

4. When t c reactor is 4~ cnevcr the eactor not not p csaurizcd vith fu in ressurizcd ith fuel in thc eactor vessel, cx pt the reactor csacl, dur thc SThRHJP CO ITIOH, sample of e react r the reactor vater s ma ntaincd vithin t 1 be coolant s ll bc at least every 96 ours lyzcd f lloving limits. for conductivity, chloride ion content, and pH.

Conductivity 10 pmho/cm t 25'C

b. Chloride 0.5 ppm

c. pH sha be betvccn 5.3 8.6.

5. When th time limits r 5. During equilibrium pover conductivity or operation an isotopic chlor de concentrat on analysis, including limi s are cxceede , an quantitative miasurcmcnta ord ly shutdovn in iatcd imacdia ely.

ll beThe for at least I-131, I-132, I-133, and I-134 shall re ctor shall be brought to be performed monthly on a the COLD SHUTDOWNS COHDITIOH coolant liquid sample.

aa rapidly aa cooldovn rate ermita.

6. Mxcnever the reactor, is 6. Additional coolant critical, thc limits on activity samples shall be taken concentrations in the rcictor vhencvcr thc reactor

'oolant shall not exceed the activity exceeds one equilibrium value of 3.2 pCi/gm percent of the of dose equivalent I-131. equilibrium concentration specified in 3.6.B.6 and one of the folloving conditions are met:

BFS 3.6/4.6-7 AMENOMENT gg, p O 8 Unit 1 PAep

3.6.B 4.6 3.6.B.6 (Cont'd) 4.6.B.6 (Cont'd)

This limit may be exceeded a. During the SThEEP COHDITIOH folloving pover transients for a maximum of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. During b. Folloving a significant this activity transient the ponr change~+

iodine concentrations shall not exceed 26 pCi/gm vhenever the c. Folloving an increase reactor is critical. The in the equilibrium reactor shall not be operated off-gas level exceeding more than 5X of its yearly 10,000 pCi/sec (at the poser operation under this steam jet air ejector) exception for the equilibrium vithin a 48-hour period.

activity limits. If the iodine concentration in the coolant d. Whenever the equilibrium exceeds 26 @CD/gm, the reactor iodine limit specified shall be shut down, and the in 3.6.B.6 is exceeded.

steam line isolation valves 11 be closed immediately. The additional coolant liquid samples shall be taken at 4 hou intervals for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, or until a stable iodine concentration helot the liNLiting value (3.2 pCi/ga) is established.

Honver, at least 3 consecutive samples shall be taken in all cases. ka isotopic analysis shall be performed for each sample, and quantitative measurements made to determine the dose equivalent I-131 concentrations

7. When ere i no fu he 7. Wh there no uel

,re tor v sel, chni 1 reacto vess 1) s ecifi tion r seto coolant ling f rei tor olant eais ry 1 s do ot apply. eNList at t chni 1 specifi tion freq ency is not required.

• • For the purpose of this section on sampling frequency, a significant pover exchange>> is defined as a change excee~lng 15Z of rated pover in less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> BFH 3.6/4.6-8 Unit 1 NENDMENT R5. Z09 N

Cl CTS p.6,g NY3>m 3.6.F 3.6.F.3 (Cont'd)

ISTIC temperature of thc reactor vessel St.'c Wus~Flc<A'a~ g,( g) water as determined by dome 9 8F~ 3,1' ) Rc c'<<culm'ova pressure. The total elapsed time in natural circulation and one pump ~Ps oPt<eh'~) i w +gs sccw>n operation must be no grcatcr than 24 hours.

4. The reactor shall not be operated with both recirculation pumps outof-service while the reactor is in the RUH mode. Following a trip of both recirculation pumps while in the RUH mode, immediately initiate a manual reactor scram.

3.6.G 4.6.Q

1. The st ctural integri of ASME Inservice inspection of AS Code C ss 1, 2, and equivalent Code Clas 1, Class 2; and compon ts shall be intaincd in Class 3 omponents shall be acco cc with Spe fication 4.6.G perform d in accordance with thro out the lif of the plant. Sectio XZ of the ASME Boile and P ssure Vessel Code and

a. Mith the stra tural integrity appli able Addenda as of any ASME ode Class 1 rcqu red by 10 CPR 5 ,

equivalent omponent, which Sec ion 50.55a(g), cept part of th primary system, ot wh re specific wri ten relief conform to the above s been granted HRC requirem ts, restore the rsuant to 10 C 50; structur 1 integrity of e ection 50.55a( (6)(i).

affectc component to w hin its 1 t or maintain e Additional i cctions hall react coolant syst in be performed n certa eithe a Cold Shutdo circumfercnt al pipe lds to cond tion or less 50'F provide add tional pr tection abov the minimum t peraturc against pi whip, w ich required by HDT co iderations, could dama c auxili ry and until each indication of a control sy terna.

defect has been invcstigated-and evaluated.

AMENDMQP'go, pp6 BFK 3.6/4.6-13 Unit 1 PAGE 5 OF '

3.6.G 4.6.G.

3.6.G. (Cont'd)

b. Wl the struct al integrity For Unit 1 an a ented o any ASME C e Class 2 3 inservice surveil ce quivalent omponent no program shall be conformi to the ab e peiformed to monitor requir ents, rest e the pot tial'orrosive stru ural integ ty of the effect of chloride res ue aff cted compo t to vithin released uring the i limit or solate the March 22, 75 fire. The ffected co onent from augmented ervice all OPERAB systems. surveillance ogram ia specified as f lovs:

a. Brows Ferry Me cal Ma tenance Instruct 53, date eptember 22, 19 5, paragra 4, defines the liquid p trant examinatio required during the f st, second, third and four refueling outages follovi the fire restoration.

b. ma Ferry Mechanical Mai ce Instruction 46, dated ly 18, 1975, hppendix defines the liquid pens t examinations re uired during the sixth refueling outage folloving the fire

.restoration.

BFH 3.6/4.6-14 AMENDIHBITlS 80 6 Unit 1 PAGg

JOL 0 s 8%

3.6.H. ggg~ 4.6.8. ~S During a modes of operatio , Ea safety-related snubber all snub crs shall be OPE s 11 be demonstrated except s noted in 3.6.8.1. 0 RABLE by performance All sa ty-related snubber f thc folloving a gmcnted arc 1 ted in Plant inservice inspect on program Surve llance Instructio and thc rcquir nts of Specificatioa .6.H/4.6.8.

l. ith onc or morc These snubber are listed in Instructions snubber(s) inope ble on Plant Survci ance a system that i required to be OPERABLE n the c 0 current plant ondition, vithin 72 ho s replace hs scd in this or restore e inoperable s cification, "typ of snubber(s) o OPERABLE ubbcr" shall me status perform an snubbers of the c engineer evaluation design and manu acturer, on the a tached compon t irrespective capacity.

02 decl rc thc attache system inoperable 2~ V folio the appropri e Limit ng Condition Snubber are categorized statement for that system. as ina essiblc or acces ible during re ctor ope tion. Each o these ca egories (inacc ssible accessible) y be nspectcd inde cndently according to c schedule dctermincd Table 4.6.H-1. e visual inspecti interval for each t c of snubber shall be de crmined based on the riteria provid in Ta e 4.6.8-1 and e first i paction intcrv 1 termincd usi this criteria shal bc based upon the pr ious inspection nterval as establis d by the requir cnts in effect before amendment No. 210 BFH 3.6/4.6-15 NEMMENT IN, 2 go Unit 1 PAG~~

Ol 4.6 H mShhma 3~

sual inspec ons shall verify that 1) the snubber has no vis le indications of damag or impaired OPBRhBI TT, (2) atta ents to th fo tion or su portiag st ture are ctional, (3) fast rs for the tachment o the snubber o the comp ent and to the snubber an orate are functio . Snubb rs which appear operabl as a result f visua inspe tions s 1 be cia ified cceptable and be reels ified acceptable or the purpose of establi ing the next visual i paction interval provided that (1) th cause of the e)ection is clearly estab shed and r edied for t particu r snubber for other s bbers espective o type that may be generi ally susceptible; and (2) the affected sn ber is functional y tested in the as-found ondition and determi d OPBRABLS per Specif ation 4.6 .5. h revie and evalu tion shall be p rformed documented to )ustify co inued operation wi an unacceptab snubber. If continued peration c ot be gusti ied, the snu er shall declared inope ble and the MITIHG COHDI IOHS POR OP TIOH shall be met.

BFH 3.6/4.6-16 AMB1BEEtlTHg, 2 IP

~Jnit 1 PAGE

C75 Z.b,h q,g, H

4. 6,8 ~SggZZa 4.6.8.3 (Cont'd) hd itional , s bbers a tached sc ions of afety-re ated systems that ve cxp rien ed un ected potenti lly amagi transi ts ines t last insp tion eriod hall be eva ated for thc poa ibil y of c cealcd d e d func onally tested confi if appl OPBlhB cable, ITf.

o Snub rs vhi have b cn mad inopcra e as re tr ltients of expected isolate d e, o other r om events, hen thc rovisio of 4.6. .7 and 4 6.8.8 e been m t and other appropriate co rectivc action implem ted, sh 11 not be counte in determining e next isual inspection interval.

BFH 3o6/4.6-17 . AMENOMENt'lN. 2 To Unit 1

4. s m ing ch refueling outage a represen tive sampl of 10K of e total of e ch type of saf ty-related ubbers in us in the pl t shall be ldll f ctionally ested either in place or n a bench test The repre tative s le selected or functi 1 testing shall incl e the variou configura iona, opera ing enviro ents, and the ange of si e and ca city of s bbers vithln the types. e representat e sample should be ighed t include m e snubb rs from severe s ice ar as such as near cavy e ipment.

The roke se ing and the secu ity of steners or attachment the sn hers to the corn onent an to the snubber chorage all be verifie on snubb rs select for FUH IOKLL TBSTS.

BPH 3.6/4.6-18 AMENDMENT NO. 2 10 Unit a~OF~

1 pAG

Cl, 0,

lAN 1g 1ggg 4.6.H. ~S u i~<<i

5. C 0 C ter The s bber CT OHAL TEST hall " erif that:

a. Activa ion restraining aetio ) is chieved in b th t ion and corn ressi vithin the sp cified range, capt t t ine tia dep dent, celer ion lim ing echani al snubb rs may be tes ed to ve fy only at activ tion takes place in oth dire tions of ravel.

b. Sn ber bleed or re ease vher required, i present i both c mpression and t ion ithin the pecifi d ange.

c. For mech ical sn bbers, the for requir to initiat .or main ain motion of the s bber is not g at eno to overs ress the attached pipi or comp nent dur therma movement, or indica e impendi fa ure of e snubber.

d. r"snubbe s specific lly equired ot to disp ace under co tinuous lo the abi, ity of the nubber to vit tand load ithout displa ement shal be, verified.

BFH 3.6/4.6-19 Unit 1

~ 6.8.

4.6.8.5 (Con d)

e. cating met ds may be used to mc ure parameters indircctl or parameters other th those specified if thos ,results correl ted to t e can be speci cd par eters thro estab ishcd me ds.

6.

kn cngin ring eva tion shall b made of ch failure to mee the FUR OKhL TEST accep ce crit ia to dete e thc ause of the fai ure. The result of this ysis s 1 be used, if plicable in select nubbers be teste in thc subscqu lot in effort to detcrai c the OPE ILITY of other ubbers v ch may bc sub) t to the e failure mod . Sclecti of snubbers fo future te ting may a o bc b scd on th failure lysis. or each s bber that does ot meet t e FUKCTIO TEST ace ptance criteri , an addi onal lot equal o 10 pere t of the rcaa cr of t t type of snu ers shall e functions ly te tcd. Tes ng shall ntinue un 1 no additi 1 noperable snubbers arc found vithin s sequent lots or all snubber of the orig 1 HJKCTI TEST typ have been teste or all susp ct snubbcrs iden fied by the failure ana sis have bc tested, as applicable.

BFH 3.6/4.6<<20 AMENDMgPNy ~ >>

Unit 1 PAGE~OF~

4.6.H. u b 4.6.H.6 (Co 'd) any snubb selected or functio 1 testing either fai to lo up or fails move, .e.,

frozen i pl'ace, he cause vill be caused valuat and cturer or if y manu desig defici cy, all snub ers of e same des gn subj t to the s e defec shall be ctiona y tested is tes ing requi ement shall b independ nt of the r uirements stated abov for snubb rs not mee ng the CTIONAL TE accept e criteria.

'r he discov missi of loose attachmen fastener vill be e luated to dete ine vheth r the cause ay be loc ized or gener c. The r ult of the valuation use to sele ill other be su pect snu ers for v rifying e attachme t stener , as applica le.

7. S a Fo the snubber s) found i operable, an engineerin valuation sh ll be perf med on the compo ents which are restrained y the snub er(s).

The purpo of this engineer g evaluati n shall be to dete ine restra ed by the if the component, S BFN 3.6/4.6-21 AMENOMBfTNg f63 Unit 1

VAJA> ivs8~

4.

4. 6.8.7 (Cont'd) snubber s) vere a ersely affect by the operability of th snubber( , and in orde to e sure that he restrained corn onent rem's capable of

,

m ting the signed service.

8 ~ u o a 0 S S b Snubbers hich fail he visual inspect on or the FUNCTI AL TEST ac eptance a shall be repaired 'rite or r laced. Re lacement snu ers and sn bers which ha e repairs v ch might a fact the FUN TIONAL TEST esults shall meet the FUNCTIONAL ST criter before inst llation i the unit. The e snubbers shall have met e accepta ce criteria subsequent to their most re ent servic , and the FUNCTI NAL TEST m st have been erformed v hin 12 mont s before b ng installed in he unit.

9.

Permanent or other mptions from vis al inspecti ns and/or unctional t sting for i ividual sn bers may be gr nted by th Commission if justifiabl basis for ex ption is p sented and if applicable nubber life destructive sting vas perform to qualify snubber OP BILITY for the appli able design conditio at either the BFN 3.6/4.6-22 AMENDMQP gP. y8g Unit 1

Cl 0,

iJAN i 9 1989 4.6.H.

4.6.8.9 ont'd) completi of thei fabrica ion or at subsequent date. Snubbers exempted shel continue o be liste in e plant i structions ith fo notes in cating the tent of t exemption

10. S e o a C

The se ice life o snubbers may b extended b ed on an eva ation of th records of ~

FU TZONAL TEST m intenance hi tory, and nvironmenta conditions to which the s bbers have been expos d.

elemMM 50. 18 8 BFN 3.6/4.6-23 Unit 1

0 0

JAN i9 1888 THIS PAGE INTENTIONALLY LEET BLANK AMENOMENT NO. 1,6 8 BFH 3.6/4.6-234 Unit 1 PAGE~OF~I W

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Table 4.6.8-1 (Continued)

JOt. 0sm SHUBBER VISUAL IHSPECTIOK IHTERVAL Hote 4: If e number of una eptable sn hers is e 1 to or ess the nuaber in lpga B but rester the num r in Co A, the next i pection terval 1 be the arne as previous inte al.

ote 5: f the number of unicceptab snubbers s equal t or, great than the number in Column , the next pecti interval shall be tvo- rds of th previous erval. ovever, i the number of una ceptable ubbers is 1 s than t e number Column C, bu greater the numb r in Col B, the ext interval s ll be red ced proporti that is, e previo interval ll lly by terpolat on, be red ced by a actor that is e-third the ratio o the diff ence be en the number o unaccep ble snubbers found dur the pr ious interva and the timber in Col B to differ e in the number in Col B and C.

te 6: The provisions of Specification 1.0. are applicable for all inspection intervals up to and including 48 months.

BFH 3.6/4.6-23c AMENOMENT IL 2IO Unit 1 PAGE

t The Bases Section 3.4, Reactor Coolant System (RCS) Bases of the current Technical Specifications for this section have been completely replaced by revised Bases that reflect the format and applicable content of the proposed Browns Ferry Unit 2 Technical Specification Section 3.4, consistent with the BWR Standard Technical Specification, NUREG 1433. The revised Bases are as shown in the proposed Browns Ferry Unit 2 Technical Specification Bases.

BFN-UNITS 1, 2, 5 3 Revision 0 pAGE~oF LI

UNIT2 CURRENT TECHNICAL SPECIFICATIPN MARKUP

Cl 0

P,l LIMITIHt COHDITIOHS FOR OPZRATIOH URVEILLAHCZ REOUIRZmHTS 3.6 S 0 4.6 S~S 0 cab Applies o the operating status Applies to the periodic of the rc tor coolant system. examination an testing requirements for c reactor coolant system.

~0~v ~Oa~v To assure the integ ity and safe determine thc condition of operation of the rca or coolant th reactor coolant system and system. thc operation of thc safety devices related to it.

t 0 sm 3.4.9. followed~

(

LCo 3.g,g 1. The average rate of 1. )During heatups and reactor coolaat temperature change during normal heatup parameters or cooldom shall not exceed shall be recorded and 100 F/hr vhca averaged over reactor coolant a oae-hour period. ~pl temperature determined attic=minute intervals un s ve readings each given lo tion are vithia F.

a earn Dome Pre sure Convert to pcr vessel rcgi temperatur )

g.4 l Reacto bottom drain tcmpc ature Re rculation 1 ops B

d Reactor ve sel bo tom head tern erature

e. Rcacto vessel shell adjacent to shell flange BFE 3. 6/4. 6-1 A >na ~

Unit 2

s

2. During all operations with Reactor vessel metal

~o a critical core, other than temperature at the for low-level physics tests, outside surface of the ezcept when the vessel is bottom head in the vented, the. reactor vessel vicinity of the control shell and fluid temperatures rod drive housing and shall be at or above the reactor vessel shell temperature of curve 03 of ad/scent to shell Pigure 3. 6>>1. flange shall be at least every minutes during inscrvice

~<'2 dc hydrostat'ic or leak test hea the vessel pressure is > 3L? psi@.

3. Daring heatup by cst spec ens nonnuclear means, except the reactor

'eprcseat when the vessel is vented vessel, e veld, and Lco or as indicated in 3.6.k.4, veld he t affected zone during cooldown folloving metal hall be installed nuclear shutdown, or in e reactor vc scl during lov-level physics a aceat to th vessel tests, the reactor vessel all at the re midplane temperature shall be at or level. Th number and above the temperatures of type of ecimens vill curve 02 of Figure 3 '-1 until be in cordance vith removing tension on the head repor KDO-10115. e stud bolts as specified in specimens shall m t the

'

6.i 5~ intent of ASIAN E 85-82.

PAGE~

<<~ Jf 3 6/4 6-2 Unit 2 AMENDMENTNO. 17 0

5 c icAF>0 SEP i 3 1995 ss a 4 ~ The beltline region of 4~

reactor vessel temperatures gCo during inservice hydrostatic) g.A or leak testing shall bc at J Si2>06 l No~ ]

or above thc temperatures shown on curve 41 of Figure Hl p~,pop sg 5. 4.9 2 3.6-1. The applicability of this curve to these tests is extended to nonnuclear SR heatup and ambient loss 3.g.9. I, cooldovn associated vith

~oR z. these tests only if the heatup and cooldovn rates do not exceed 15 F per Sg K.iJ.).S d Na4. I houre S'g?.q.'t-g + Uo~

sg s.g.) 7 p No+

5. The reactor vessel head 5. When the reactor vessel head bolting studs may be partially bolting studs are tensioned tensioned (four sequences of and the reactor is in a cold the seating pass) provided condition, the reactor vessel the studs and flange materials shell temperature haaediatcly are above 70'F. Before belov the head flange shall loading the flanges any morc, be l QO the vessel flange and head 3qq flange must be greater than 82 F, and must remain above 82 F vhile under full tension.

P o~H C~p e<<dc5 gc. K~ g.gq g ( pg PAGE OP AMENDMENTNO. 239 BFK 3 '/4.6-3 Unit 2

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~AI 4.6.E. ~Je RmSm 2~ Whenever there is

~c4 Gw~ifi<4ia~ waar 6 "~~gu recirculation flov vith 4~[ the reactor in thc gl57$ 3,'I 2 SThRTUP or RUH Node and one recirculation pump is operating, thc diffuser to lover plenum differential pressure shall be checked daily and the differential pressure of an individual get pump in a loop shall not vary from the mean of all get pump See Z~S] "Ia.h'~ 4- Ct ~)~ differential yrcsaures 8~~ Isis Z.q.i in that loop by more than 10K.

3:6.F 4 '.F.

1. The reactor shall not bc operated 1.. Recirculation pump speeds vith one recirculation loop out shall bc checked and logged of service for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. at least once per day.

With the reactor operating, onc recirculation loop is out of if service, the plant shall be placed in a HOT SHUTDOWH COHDITIOH vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless the loop is sooner returned to service.

2. Folloving one pump operation, 2. Ho additional surveillance the discharge valve of the lov required.

speed yump may not be opened unless the speed of thc faster pump is less than 50K of its rated speed 3 When the reacti5mis not-4n the RUH mode, REhCTOR POWER sg 3.0.R.'t OPERATIOH vith both recircu- 3. Before starting either lation pumps out-of-service recirculation pump for to 12 during REACTOR POWER such interval, restart of h'ing OPERATIOH 5g, the recirculation pumps ia /Al c s rgc g.], t.'f pcrmittcds provided the loop tcmperaturc and dome gq<c > aischirge temyerature is vithin saturation temperature.

75 F of the saturation temperature of the reactor BPH 3.6/4+6-12 AMENOMBlTg6. 22g Unit 2 PAGE ~. OF Q

s ~)Sic.$ (u~ 3.1 7 NR i 8 1993 3.6.F 3.g,Q,f, gott 2 vessel water as determined by dome pressure. e a e apse t e in natural circulation and one pump J operation must be no greater 5tc d~gk4j~~'c~ c~ 40~r than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

~ Isi5 gc/, I L~ The reactor shall not be operated with both recirculation pumps out-of-service while the reactor is in the RUN mode. Following a trip of both recirculation pumps while in the RUN mode, immediately initiate a manual reactor scram.

4.6.G The structural integrity of Inservice inspection of ASME ASME Code Class 1, 2, and Code Class 1, Class 2, and 3 equivalent components shall Class 3 components shall be be maintained in accordance performed in accordance with with Specification 4.6.G Section XI of the ASME Boiler throughout the life of the and Pressure Vessel Code and plant. applicable Addenda as required by 10 CFR 50, Section 50.55a(g

a. With the structural except where specific written integrity of'ny ASME relief has been granted by NRC Code Class 1 equivalent pursuant to 10 CFR 50, Section component, which is part 50.55a(g)(6)(i).

of the primary system, not conforming to the above requirements, restore 2. 'dditional inspections the structural integrity of shall be performed on the affected component to certain circumferential within its limit or maintain pipe welds to provide the reactor coolant system in additional protection either a COLD SHUTDOWN against pipe whip, CONDITION or less than 50'F which could damage above the minimum temperature auxiliary and control required by NDT consider- systems.

ations, until each indication of a defect has been inves-tigated and evaluated. II i'FN Stc. WHsgllcr,$ ~ @ g Cw5 gg g/qg Cg 3 6(4 6 13 AMENOMBF gy, p 06 Unit 2 PAGE~OF

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3.6.B. 4 '.BE

1. PRIOR TO ST and 1. Reactor coolant shall be at steami rates c tinuously monitored less than 00,000 or conductivity. except vhen Ib/hr, c folloving there is no fuel in the limits shall apply. reactor vessel.

a. onductivity, a. Whenever'he pmho/cm at 25 C 2.0 continuous conductivity monitor is inopcrablc, Chloride, ppm 0 a sample o reactor coolant 11 be analyz for cond tivity every 4 rs except as 1 tcd belov.

cactor is in COLD If the, SHUTDOWN COHDITIOEg a of reactor 'ample coolant shall be analyzed for conductivity every 8 hours.

b. Once a veek t e continuous nitor shall bc ected vith an in-li flov cell.

This i ine condu ivity cal ration ahall be p formed every 24 ura vhenevei the reactor coolant conductivity is >1.0 pmho/cm at 25 C.

2. At steaming rates During startup prior to greater than 100,000 pressurizing thc reactor

'b/hr, the folloving above atmospheric limits shall apply. pressurcg measurements of reactor vatcr polity

a. Conductivity, shall be performed to ahov idaho/cm at 25'C 1 0 conformance vith 3.6.5.1 of limiting conditions.

b. Chloride, ppm 0.2 BFS 3.6/4.6-5 AMENpMENT RI. 224 Unit 2 PAGF / OF~

P rs'~war r I '

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3.6.B. Cao an ist 4.6.B. Coa em st

4. When th reactor is 4q enever the re ctor is not not pr ssurized vith fuel in pressurized v h fuel i the r actor vessel, exce t the reactor essel, a dur the STARTUP CO TIOH, sample of e reactor th reactor vater sha be coolant all be ana zed intained vithin t at lea every 96 ho rs olloving limits. for c cdcctivity, loride ion ontent and pH.

a. Conductivit 10 pmho/ at 25'C

b. Chlori - 0.5 ppm

c. pH s ll be 5.3 and Se6.

betve

5. When the time lim ts or 5. During equilibrium pover um conduct ity or operation an isotopic oride conc tration analysis, including imits are ceded, an quantitative measurements orderly shu ovn shall be for at least I-131, I-132, initiated ediately. The I-133, and I-134 shall reactor 11 bc brought to bc performed monthly on a 0 6.

the as COLD SHUTDOWH COHDITIOH rapidly permits.

ene as. cooldovn e reactor is rate 6.

caolant liquid sample.

Additional coolant critical, thc limits an activity samples shall be taken concentrations in the reactor vhencver the rcactar coolant shall not exceed the activity exceeds onc equilibrium value of 3.2 pCi/gm percent of thc of dose equivalent I-131. equilibrium concentration specified in 3.6.B.6 and one of the folloving conditions are .met:

S<d'fdic~~<FiCV T<aM p'~A C RAhl

'~

g~ ~ St h/ lg Q~

Y'4<s st=<7, g

'-1 2 24 BFH Unit 2 3'.6/4 AMENOMENT NL pAGE 0p if

0

<~$ : 3.c. E/Mdiv JUN 2 8 )PE 3.6.B. 4.6.B. o 3.6.B.6 (Cont'd) 4.6.B.6 (Cont'd)

This limit may bc exceeded a. During the STARTOP COHDITIOH folloving pover transients for a maxim'f 48 hours. During b. Pollovtng a signfficant thfa activity transient thc pover change**

iodine concentrations shall not exceed 26 pCi/gm vhcnever the c. Folloving'n fncreaac reactor is critical. Thc in thc equflfbri~

reactor shall not bc opcratcd off-gaa level exceeding morc than SX of ita yearly 10,000 pCf/sec (at thc povcr operation under this steam get air ejector) exception for thc equilibrium vithin a 48-hour period.

activity limits. If the iodine concentration in thc coolant d. Whenever the equilibrium exceeds 26 pCi/gm, the reactor iodine limit apecifi'cd shall be shut dovn, and the in 3.6.B.6 is czcecded.

stem line isolation valves shall be closed immcdiatcly. Thc additional coolant liquid samples shall be taken at 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> intervals for 48 hours, or until a stable iodine concentration belov the limiting value (3.2 pCi/gm) is established.

Hovcvcr, at least 3 consecutive X6C ~TIE'ICWnoN wc~ simples shall be taken in all

<~" ~~ R'4 814 Is~s cases. kn isotopic analysis 3.'/.6 i~ ~(g zpcvaQ shall bc performed for each ample, and quantitative measurements made to determine the dose equivalent I-131 concentratio

7. Wh there is o fuel in thc there is no fuel in thc r actor vesa , technic 1 eactor vcsa , aampli of pecificat n reactor oolant reactor c ant ch try t chemiatry fmits do ot apply. technic specific ion frequency ia not rcquir d.

• • Por the purpose of this sectfon on sampling frequency, a significant povcr cxchu~e is defined as a change exceeding 15K of rated pover in less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

BFH 3.6/4.6-8 AMENOMEgl'ltd. 2 pg Unit 2 PAGE V OP l~

CTS R.C,g/+gg J

NR i 8 Igga 3.6.F 3.6.F.3 (Cont'd) Sce 34$ 4iPic4)jo~ peg W RFIV ISTIC 3.'f./ Peci~c l7 vessel water as determined LooPS OpC~4~ i~ /hit by dome pressure. The z ~ec4o~

total elapsed time in natural ci.rculation and onc pump operation must be no greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4. The reactoi shall not be operated with both recirculation pumps out-of-service while the reactor is ia the RUN mode. Followiag a trip of both recirculation pumps while in the RUN mode, imnediately initiate a manual reactor scram 3.6 ~ G 4.6.G The structural 'egrity of Inservice inspection ASME ASME Code Clas 1, 2, and Code Class 1, Class , and 3 equivalent components shall Class 3 components 11 be be maintai d in accordance performed in acco ance with with Spec'cation 4.6.G Section XI of t ASME Boi.ler through t the life of the and Pressure V esel Code and plant. applicable A eada ae required by 10 CFR 5 , Section 50.55a(g

a. ith the structural except wh e specific written integrity of any ASME relief s been granted by NRC Code Class 1 equivale pure to 10 CFR 50, Section component, which is art 50.55 (g)(6)(i).

of the primary sys not conforming to the above requirem s, restore dditional inspections the structural integrity of shall be performed on the affected omponent to certain ci.rcumferent 1 within i.ts imit or maintain pipe welds to prov e the react coolant system in addi.tioaal prote ion either a COLD SHUTDOWN against pipe w p, CONDIT N or less than 50'F which could d gc above the minimum temperature auxili,ary control req red by NDT consider- systems.

at'ons, until each indicatio a defect has been inves tigated and evaluated.

BFN 3.6/4.6-13 AMENDMBfT%7. 206 Unit 2 pAGs + o~ ~

c~ a.c.g/VC g.

MAR I 8 1993 3.6.G 3.6.G.l ont'd)

With the struc al integrity of any ASME de Class 2 or 3 equivalent omponent not conformi to the above requir ents, restore the struc al integrity of ted component to w in t'ff it limit or isolate t e a fected component fr m all 0 ERABLE systems.

BFN 3.6/O.6-l4 AMENOMENT NO. 206 Unit 2 PAGE

During all mo es of operation, Each safety-related snubber all snubber shall be OPERABLE shall be demonstrated except as oted in 3.6.8.1. OHHtkBLE by performance All saf y-related snubbers of the folloving, augmented are 1 ted in Plant inservice insped'tion program Surv llance Instructions. and the requirements of.

Specification 3.6.8/4.6.8.

1 With one or more These snub rs are listed in snubber(s) inoperabl on Plant Su eillance Instructions. I a system that is re ired to be OPERABLE in e current plant co ition, vithin 72 hours replace ks used in this or restore th inoperable specification, "type of snubber(s) t OPERABIS snubber" shall mean status and erfora an snubbers of the same engineer evaluation design and aanufac er, on the a tached component irrespective of ca city.

or decl re the attached system inoperable and 2~ V follov the appropriate Limiting Condition Snubbers are ategorixed statement for that system. as inaccess le or acceseibl during reactor operatio . Each of these categor cs (inaccessible and ac essible) may be inspe ted independently according to the schedule determined by Table 4.6.8-1. The vi inspection interv for each type of ber shall be determined ed upon the criteria rovided in Table 4.6.8 and the first inspection nterval determine using this criteria shall be based upon th previous inspection interval as established by the requirements in amendment No. 225 effect'efore BFH 3.6/4.6-15 AMENOMEHT R0, p 25 Unit 2 PAGE~O~~

4.6.H.

3~

Vis inspections shall v fy-that (1) the abber no visible indi tions of dsaae or iepai ed OPERLBILITY; (2) attachments to c foundation o supporting structure e functional, and (3) teners for the etta'cha t of the snubber to th component and to the snub r anchorage are f tional. Snubbers vhich a ar inoperable as a esult of visual inspectioni shall b classified unacce able and aalu be reclassif ed acceptable for e purpose

. of establis the next visual insp ction interva.

provided t (1) the cause of the r /ection is clearly establ hed and reaedied for t particular snubber and or other snubbers irr pective of type t be generically susceptible; and ) the affected snubbe is functionally sted in the as-found co ition and detezained PERABLE per Specific ion 4.6.8.5. k review evaluation shall be per ormed and documented to ) tify continued ope tion with an unacceptable snubber If continued operatio cannot be /ustified, th snubber shall be decla d inoperable the LIMITIEG COSDITIOHS R OPBIRTIOH shall be me 0 BPS Unit 2 3.6/4.6-16 OMENS NJ; p 25 pAGE~OF~

0 4.6.8.3 (Cont'd)

~ k tionally, snubbers tached to scctio of safety-related s tees that have experienc unexpected potentially aaaglag transient since the last inspect n period shall bc evalua ed for the poss ility of concealed d e and functionally tc tcd, if applicable, to nfirm OPBRABILITY nubbcrs which ha been made inoperable thc result of un ected transients, solated daaage, o other random events, en thc provisions of 4.6 .7 and 4.6.H. have been ct and any o r app opriate corre ive ac ion implemen d, shall not be counte in determining c next visual inspection terval.

3.6/4.6<<17 NENOMENT Ng. p g5 BFH Unit 2 PAGEOS~

4.6.H. ~S~~s ~

4~

ing each refuel tagc, a reprcs ative sample of 10K o the total of each type o safety-relet d snubbers in use in thc lant shall be functio ly tested either in pla or in a bench test.

The representative sample a ected for functional eating shall include the various configuratio operating environm ts, and the range of size and capacf ty of scc srs sithin the types.

rcprescntat e sample should be eighed to

. include orc snubbers from severe crvicc areas such as n r heavy equipment.

stroke setting d thc security of fast rs for attachment of th snubbcrs to thc compon and to the snubber anch age shall be verified o snubbcrs selected or FUKCTIOKlL TESTS.

BFH 3.6/4.6-18 AMENDMENT go. p p6 Unit 2 Gp~dOP~~

0 JAN 18 1888

.6.H.

5.

e snubber FUHCTIOHhL TEST shall verify that:

a. hctivation (re raining action) is a ieved in both te ion and compress n vithin the specif ed range, except tha nertia dependent, a eleration limiting echanical snubbers may be tested to verify only that activation takes place in both 4

directions of trav

b. Snubber bleed, r release vher required, is present n both compress n and tension vithin he specified rang o

c. or mechanical snubbers, the force required to initiate or maintain motion of the snubber not great enough to overstress the a ached piping or comp ent during, the movement, or to ind ate impending failure f the snubber.

d. Fo snubbers specifically quired no t to displace under continuous load, the ability of the snubber

~

to vithstand load vithout displacement shall be verified.

BFN Unit 2 3.6/4.6-19 AMENDMENT NL l 69 PAG~~r't:~8'

C C7S S.g.g 6.g P JUL 055%

.6 H.

4.6.8.5 (Cont'.

eating methods may be used to measure parameters indirectly or parameters other than those specified if those results c correlated to the be specified param ers through estab shed methods.

6.

ka ineering evaluation 1 be made of each failure meet the PORCTIOEhL TEST acceptance criteria to determine the cause of e failure.

analysis shall The applicable, in sel cting be, result this if snubbers to be t ted in the subsequent lot n an effoxt to determine th OPERABILITY of other snub rs which may be sub)ect the same failure mode. election of snubbers for f ure testing may also be bas on the failure sis. For each snubber t does not meet the CTIOKAL TEST acceptance criteria, an additional lot equal to 10 percent of remainder of that type f snubbers ahall be fun ionally tested. Testing s 1 continue until no dditional inoperable snubb s are found vithin subsequ t lots or all snubbers of e original tOICZZOELL tyya hare been tested or all suspect snubbers

)

identif d by the failure analys s have been tested, as applicable.

BFH 3.6/4.6-20 ~

AIH<n~an e. p pq Unit 2 PAGE~iOF /

4.6.H.

4.6.H.6 (C 'd)

If any snubber selected for functional test either fails to croup or fails to e, i.e.,

frozen in ace, the cause vf.ll b valuated and if caus by manufacturer or d ign deficiency, all snubbers of the same design subject to the same defect shall be functionally tested.

This testing requirem shall be independen f the requirement tated above for s ers not meeting e FUNCTIONAL TEST cceptance cri,teria.

The discovery of loose or missing attachment fasteners vill be evaluated to determine vhether the cause may be. localize or generic. The res of the evaluation'l be used to sel other suspect ubbers for veri ng the attachment teners, as applicable.

7.

For the snubber(s) und inoperable, an e neering evaluation s be performed on the co nents vhich are restra ed by the snubber(s).

Th urpose of this ineering evaluation shall be to determine if restrained by the the components BFN 3. 6/4. 6-21 NmoMen R. I SO Unit 2 waco~ ~

JAN f 9 1888 4.6.H.

4.6.H.7 t')

snubber(s) e adversely affecte y the inoperability of snubber(s), and in orde ensure that the restrained component remains capable of meeting the designed servic 8 ~

u b s Snubbers v fail the visual inspect or the FUN NAL TEST acceptance c teria shall be repaired or replaced. Replacement snubbers and snubbers Which have repairs vhich might affect the FUNCTIONAL T results shall meet t FUNCTIONAL TEST teria before instal ion in th>>

unit. Th snubbers shall have m the acceptance cr ria subsequent to their st recent service, and the FUNCTIONAL TEST must have been performed vithin 12 months before being install in the unit.

9. V ua anent or other exemptions from visual inspections and/or functional testing for individual snubbers y be granted by the C ssion if a justifiable asis for exemption is esented and if appli ive e snubber life dest :esting v performed to qualify snubber OPERABILITY for the applicable design conditions at either the

~

BFH 3.6/4.6-22 @t)MENT NO. X6 0 Unit 2 PAGp~o

4. .H.

4.6.8.9 (Cont' pletion of their fabrication or at a s sequent date. Snubbers so empted shall continue be listed in the plant tructions with footnotes icating the extent o the exemptions.

e service life of sn bees may be extended base on an evaluation of the ecords of FUNCTIONAL TEST maintenance h tory, and environment conditions to vhich the ubbers have been exp sed.

BFN 3.6/4.6-23 AMENOh)BIT ND. X6 0 Unit 2 PAGp~50F~

'JAN 19 $888 THIS PAGE IHTEHTIORALLY LEFT BLANK NENtjMENT NO. X 6 0 BEE 3 '/4.6-23a Unit 2 rs a~~koF~S

ble 4.6 H-1 SHUBBER SUAL IHSPECTIOH IHTERVAL Population Column A Column B Column C or Catego Notes Extend Interval Repeat Int al Reduce Interval 4 e Hote 1: The next visual inspection interval or a snubber population or category size shall be determined ased upon the previous inspection interval and the n er of unacceptable snubbers found during that interval. ubbers may be categorized, based upon their accessibility d ing pover operation, as accessible or inaccessible. These tegories may be examined separately or )ointly. Hovever, e licensee must make and document t decision before any pection and shall use that decisio as the basis upon wh to determine the next inspection erval for that categ Hote 2: Interpola on between population or category siz and the number unacceptable anubbers is permissible Use next lover integ for the value of the limit for Col tha integer includes a fractional value A, B, or C unacceptable if snu ers as determined by interpolatio Hote 3: If the number of unacceptable snub rs is equal to or less than

,the number in Column A, the nex inspection interval may be twice the previous interval not greater than 48 months.

BFH Unit 2 3.6/4.6-23b FINED'8~(

T le 4.6.8-1 (Continued)

S BBR VISUAL IHSPBCTIOH IHTERVAL Hote 4: If th umber of unacceptable snub rs is equal to or less eater than the number in the number in Column B but Co A, the next inspection terval shall be the same as e previous interval.

Hote 5 If the number of unacce able snubbers is equal to or greater than the number in Co C, the next inspection int al shall be two-third of the previous interval. How er, 'if the number of unacce able snubbers is less than the umber in Column C, but eater than the nuaber in Col , the next interval be reduced proportionally by terpolation, that is, previous interval shall be r ced by a factor that is e-third of the ratio of the d ference betveen e number unacceptable snubbers found uring the previo interv 1 and the number in Column B o the difference the numbe in Columns B aud C.

Hote 6: The provisions of Specificatio 1.0.LL are applic le for all inspection intervals up to including 48 mon BPH 3.6/4.6-23c AMENOMENT RQ. p Zg Unit 2 p.<gE~$ 'F~3'

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP PAGE~OF g

'n LIMITIHt COHDITIOHS FOR OPERATIOH SURVEILLAHCE REQUIREMEHTS 4.6 Applies t the operating s atus plies to the p iodic of the res or coolant syst ination and t ting req rements for th reactor cool t system.

To assure the integr and safe To dete the condition of operation of the react r coolant the reactor oolant system d systeme the operation f the safety devices relate to it.

ill t

1. The average rate of  !

DO S 't.g reactor coolant temperature <Mgcooldoms, the change during normal heatup c ggAQ, ) following parameters or cooldoma shall not exceed shall be recorded and 100 F/hr shen averaged over reactor coolant a one-hour period. temperature determined ute intervals 36 til 3 succ s ve readings a each given lo tion vithin F.

a. team D e Press e (Conve to upp vess region t erature)

b. actor ttom drain empera re Reci culatio loops A B

d. eactor v ssel bottom head tern erature

e. React vessel shell ad)a ent to shell fl e BFS 3.6/4.6-1 PAGE~pp~

Unit 3

5 3'.M..

2. During all operations vith eactor vcsscl metal a critical core, other than temperature at the for lov-level pbysics tests, outside surface of the LCg .except vhcn thc vessel is bottom head in thc vented, the reactor vessel vicinity of thc control shell and fluid temperatures rod drive housing and shall be at or above the reactor vessel shell temycratare of carve 03 of ad)accnt to shell Figure 3.6-1. flange shall be recorded at least every LZ minutes daring ervice hydrostatic or test~ cn the vesee 5g g,q,fj,)~ ressurc is > 312 psig

3. Daring heatap by 3. Test specimens nonnuclear means, exccyt reyresent the reactor when the vessel is vented vessel, b e veld, and LCo or as indicated in 3.6.h.4, veld hea affected zone daring cooldown folloving metal I be ins alled 3A g nuclear shutdown, or in th reactor v sel daring lov-level physics aQ ent to the cssel tests, the reactor vessel at the c c mi plane temperature shall be at or level. The be and above the temperatures of type of sp im vill curve $ 2 of Figure 3.6-1 antil be in acc vith GE removing tension on the head reyort lKDO-10 15. The stad bolts as specified in specimens shall meet the 3.6.L.5. intent of hSTN E 185-82.

PAGE OP~

BFH " 3 '/4 '-2 AMENDMENTNO. 14 Unit 3 1

l.i

<Pc c a 'P i3 1995

4. The beltline region of reactor vessel temperatures LC.O (during inservice hydrostatic 9'g.9 or leak testing ahall be at SRg.g.g. l Nog )

or above the temperatures shown on curve ¹1 of Figure 3.6-1. The applicability of p) y p~g sC. 9.'L9.2.

this curve CD Chese.Ccats is cztended to ncmnuclear 5$ heatup and aabient loss

'3A.g, cooldom associated with

)

NnH'.g, these tests only if the heatup and cooldem rates do not exceed 15 F per hour>> ~R ~~9 ~ 9e (>> +bloke, sg z.q,9.a+.Mom

5. The reactor vessel head 5. When the reactor vessel head bolting studs may be partially bolting studs are tensioned tensioned (four sequences of snd the reactor is in a Cold the seating pass) provided Condition, the reactor vessel Che sCuds and flange. IaCerials t eratur imediately are above 70 F. Before below'he head flange shall loading the flanges any more, be LC.b the vessel flange and head 3 9.1 flange must be greater Chan 70 F, and Itust reaain above 70 P whfle under fuX1 tensicm.

Prod ~w~c~

Pr 5',g,),5>

PAGE OF 3.6/4 '-3 AMENDMENTNg. y98 BFK Unit 3

ecifim '3 I ~

+@i

+ 3'. o9. PJo )

6. The pump in an idle 6. r urfag recirculation loop shall not ST of an idle be started unless thc rec rculation loop, the temperatures of thc coolant temperature of the reactor vi in thc idle o erat ng coolant the operat recirculation loo are w 5D F of each other.

and die loops

+y o c l bc

7. The reactor recirculation Prior to atartiag a pumps shall not be started recircu ation pump, I Co unless the coolant the reactor coolant

$ ,4,cj temperatures betveen the temperatures in the dome and bottom head dome and in the bottom drain are vithin 145 F. head drain shall bc compare p ~~>~ Pcy IeN$

M3 p, g~~

PAGE OP~

BPS 3.6/4.6W Unit 3

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2. Whenever there is recirculation flov wit the reactor in the Sc< 'Sus+t Ei'rc4onQ~ c~ey STARTUP or RUN Mode and

+~ >F'N iSTS 3q.~ one recirculation pump I is operating, the diffuser to lover plenum differential pressure shall be, chcckcd daily and the differential pressure of an individual jet pump in a loop shall not vary from thc mean of all jet pump differential pressures 5<@ 5gs+iCi ca/ion Q~ cha<g~< in that loop by more kr'P'hl l5T5 SI I than 10'.

3.6.F at 0 4.6.F e 0 tio

1. The reactor shall not bc operated 1. Recirculation pump vith onc recirculation loop out speeds shall be checked of service for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. and logged at least Pith the reactor operating, if once per day.

one recirculation loop is out of service, the plant shall be placed in a HOT SHUTDOWH COHDITXOH vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> unless thc loop is sooner returned to service.

2. Folloving onc-pump operation, 2. Ho additional the discharge valve of the lov surveillance required.

speed pump may not be opened unless thc spccd of the faster pump is less than 50K of its rated speed.

~R

3. When thc reactor is not in thc RUH 3. Before starting either mode, REhCTOR POWER OPERhTIOH with recirculation pump both recirculation pumps out-of- during REhCTOR POWER service for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> i OPE &Bd' ermitted Dur ng such interval e loop dis arge restart of thc recirculation pumps temperature and dome sR is permitted, provided the loop saturation temperature.

9.g discharge temperature is vithin 75 F of the saturation temperature pAGE~OF~

BFH 3.6/4.6-12 AMENDMgfTNP. y 8$

Unit 3

.6.F See V<S+Pi~gon kr C 3,9A,9~ Ivo& 2. $ r Bpe Isis r,v.j of the reactor vessel water as determined by dome pressure. The a e apse t e n natural circulation and one pump operation must be no greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4. The reactor shall not be operated with both recirculation pumps out-of-service while the reactor's in the RUH mode. Following a trip of both recirculation pumps while in the RUH mode, immediately initiate a manual reactor scram.

3.6.G 4.6.G The structural integrity of ASME 1. Znservice inspection of ASME Code Class 1, 2, and 3 equivalent Code Class 1, Class 2, and components shall be maintained ~

Class 3 components shall be in accordance with Specification performed in accordance with 4.6.G throughout the life of the Section XX of the ASME Boiler plant. and Pressure Vessel Code and applicable Addenda as required

a. With the structural integrity by 10 CFR 50, Section 50.55a(g),

of any ASME Code Class 1 except where specific written equivalent component, which relief has been granted by HRC is part of the primary system, pursuant to 10 CFR 50, Section not conforming to the above 50.55a(g)(6)(i).

requirements, restore the structural integrity of the 2. Additional inspections shall be affected component to within performed on certain its limit or maintain the circumferential pipe welds reactor coolant system in either to provide additional a Cold Shutdown condition protection against pipe whip, or less than 50 F above which could damage auxiliary the mintunun temperature and control systems.

required by HDT consider-ations, until each indication of a defect has been investigated and evaluated.

3ietifiaaiion 6r Cjgunyg for C T5 y,i, p./q BFH 3.6/4.6-13 AMENOIHEgf gg, ypg Unit 3 A8~ $ OF~~

.8 V.S.Z JUN 2 8 199$

3.6.B. 4.6.BE

1. PRIOR TO ARTUP and l. eactor coolant shall be at steam rates continuously monitored less t 100,000 for conductivity except when lb/hr the following there is no fuel in the limi s shall apply. reactor vessel.

a Conductivity, a. Whenever ghe pmho/cm at 25 C 2 continuous onductivity monitor inoperable,

b. Chloride, ppm 0.1 a samp of reactor cool shall be ana zed for c ductivity every hours except as listed below. If the

~

I I

reactor is in COLD SHUTDOWH COHDIT105, a sample of reactor coolant shall b analyzed for conductivi every 8 hours.

b. e a week the ontinuous monitor shall be checked with an in-line flow cell.

This in-line conductivity calibration shal be performed eve 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> whenev the reactor coo t conductiv is >1.0 ymho/cm t 25iC,

2. kt steaming rate 2. During st tup prior to greater than 10 ,000 pressur ing the lb/hr, the fo owing reactor'bove tmospheric limits shal apply. pre ure measurements o reactor water quality

a. Conductivity, hall be performed to show pmho/cm at 25'C 1.0 conformance with 3.6.B.1 of limiting conditions.

b. Chloride, ppm 0.2 BPK 3.6/4.6-5 AMENDS@ ~0. I8 Unit 3

~AGE / OF

Ci CTS Z.(,8 q.a.g OEC 0 7 1994 4.6.B.

3~ ht steaming rates 3~ Whenever the reactor greater than 100, 0 is operating (including lb/hr, the react HOT SThHDBY COHDITIOH) water quality measurements f reactor exceed Specifi tion vater quali shall be 3.6.B.2 only'r the performed ccording to time limits pecified the foll ing schedule:

belov. Exc eding these time limi or the folloving a. oride ion content maximum ality limits shall d pH shall be be caus for placing measured at least once the re tor in the every 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />.

COLD OWH CORD IOH. b. Chloride ion content sha be Conductivity measured a least time above every 8 h rs 1 idaho/ at 25iC- vhenever reactor 2 ve /year. conduc vity is Limit >1.0 o/cm o/cm at 25 C at 'C.

'0

c. sample of reactor

b. oride coolant shall be concentration ti e measured for pH at above 0.2 p least once every 8 2 vecks/ye hours vhenever the Maximum Lim reactor coolant Oo5 ppme conductivity is >1.0 idaho/cm at 25iC.

c. The rea or ahall be placed in the SHUTDOWNS COHDI IOH if pH <5.6 or

>8.6 for a 24-hour period.

BPH 3.6/4.6-6 N>NEON. 86 I Unit 3 PAGE

3.6.B. .6.B. Coo t st

4. When the eactor is 4. Whenever t e react r is not not pre urized vith f 1 in pressuri d vith uel in the re tor vessel, cept the rea or ves 1, a duri the SThRTUP HDITIOH, sampl of the eactor the eactor vater 11 be cool t shall e analyzed mai tained vithin the at east ev 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> fo loving limit . f conduc vity, chloride on conten and pH.

Conductiv ty-25 10 pmho cm at

b. Chio de 0.5

c. p shall be tveen

.3 and 8.6

5. Wh the tim limits or 5. During equilibrium pover co ctivity or operation an isotopic oride c ncentration analysis, including limits ar exceeded, an quantitative measurements ordirly hutdovn shall be for at least I-131, I-132, initia ed immediately. The I-133, and I-134 shall react r shall be brought to be performed monthly on a the OLD SHUTDOWH COHDITIOH coolant liquid sample.

as apidly as cooldom rate permits.

6. enever e reactor is 6. hdditional coolant critical, the limits on activity samples shall be taken concentrations in the reactor vhenever the reactor coolant shall not exceed the activity. exceeds one equilibri~ value of 3.2 pCi/gm percent of the of Section dose equivalent I-131. equilibrium concentration specified in 3.6.B.6 and one of the folloving conditions are met:

S<c 3'u.~f;~/on QP.

C~ge< t S~nt isis s,g,g BFH 3.6/4.6>>7 AtaENoMENT go. y8 y Unit 3 PAGE

3.6.B. 4.6.Bi 3.6.B.6 (Cont'd) 4.6.B.6 (Cont'd)

This liait Nay be exceeded a. During the STARTUP CORDITIOK folloving, pover transients for a aaxiarm of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. During b. Folloving a significant this activity transient the pover chLnge**

iodine concentrations shall not exceed 26 pCi/gw vhenever the c. Follovtng .an increase reactor is critical. The in the squilibritm reactor shall not be operated off-gas Xerel exceeding aore than 5Z of its yearly 10,000 pCi/sec (at the pover operation undir this steaa )et air e)ector) exception for the equilibrium vithin a 48-hour period.

activity liaits. If the iodine concentration in the coolant d. Whenever the equilibrhm exceeds 26 pCi/ga, the reactor iodine liait specified shall be ahut dovn, and the in 3.6.B.6 is exceeded.

steaa line isolation valves shall be closed iwaediately. The additional coolant liquid saayles shall be talon at 4 for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, or until hour'ntervals See

~n V~q6<i'm~n $ r.

>s Vs r.q,(.;~;,

~~ a stable iodine concentration belov the liaiting value (3.2 yCi/ga) is established.

Scc ho g Hovever, at least 3 consecutii saaples shall be taken in all cases. An isotopic analysis ahall be perfozaed for each sawple, snd quantitatire aeasureaents aade to deteraine the dose equiralent I-131 concentration.

7~ the e is fuel in the 7. en ther is fuel actor esse , te cal e reac r v sl) pecif cati reac r coolant saapl of r ctor c olant cheai try 1 ts do not apply. cheai ry a tschni 1 spec ficat on fra ency is t requi ed.

For the purpose of this section on saapling frequency, a significant pover exchange is defined as a change exceeding 15Z of rated pover in less than 1 hour.

BFN 3.6/4.6-8 NENBMgpgQ, z gz Unit 3

'AGE~OF~~

tl

.6.F 0 a 3 ',F,3 (Cont'd) of the reactor vessel water as determined by dome pressure. The see swiJ"cqAo*

~ B~H >~T~ 3'~

k, C+~

total elapsed time in natural ~ Pgcirculq~

circulation and one pump 9 p a +His 5ecti on s

operation must be no greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4. The reactor shall not be operated with both recirculation pumps out-of-service while the reactor is in the RUH mode. Following a trip of both recirculation pumps while in the RUH mode, immediately initiate a manual reactor scram.

~ 6.G S U 4.6.G The struc ral integrity of ASME 1. nservice pection f ASME Code Cla 1, 2, and 3 quivalent Code Clas 1, Class , and compon s shall be intained Class 3 omponents hall be in acc dance with S ecification perform d in accor ance with 4.6.G hroughout t life of th Sectio XI of the ASME Boiler plan ~ and P essure Ves el Code d appl cable Add a as re ired

a. With the s ctural int rity by CFR 50, ction 50 55a(g) of any Code Class ex ept where ecific itten equival t component, which r ief has b grant by HRC is pa of the pr system, rsuant to 0 CFR 50, Section not onforming to e above 0.55 (g)(6 (i).

re irements, res ore the s ctural inte ity of the 2. Additio inspect ons shall be ffected compo ent to with perform on cert in its limit or intain the circum rential ipe welds reactor coo t system i either to pr ide addi ional a Cold Shu own conditi prot tion aga nst pipe whip, or less t 50'F abov whi could d ge auxiliary the min temperatu e and control s stems.

~

requir by HDT cons der-atio , until each ndication of a defect has be n investigated and evaluated.

BFH 3.6/4.6-13 AMENDafEHT NO. r 7'9 Unit 3 PAGE~OF~~

a vs 3. 6.g./q, 0. 4-NY31m 3.6.G 4 ~ 6.G 3.6.G.l ( ont'd) b With t structu al integ ity of ASME Co Class 2 or 3 equ alent co onent no co forming t the abov r quirement , restor the tructura integrity of the affected omponent o vith its lim or isol e the affect OPE d compon syst from l BFH 3+6/4+6-l~ AMENDMENT NQ. g7g Unit 3 PAGE~OF /

0

3. 6.8. 4QQhhCXk 4 6 8 2m8hma During all modes operation, Each sa ety-rclatcd snubber all saubbcrs sha be OPERABLE shall e demonstrated except as noted n 3.6.H.1. OPE by performance hll safety-rcl ed snubbers of e folloving augmented are listed in lant i rvice inspection program Surveillance astructions. thc requirement of pecification 3.6. 4.6.8.

1. With o or more These snubbers ar listed ia snubb (s) inoperable a Plant Surveill e Instructions a sys em that is re red to b OPERhSLE in cur cnt plant cond ion, wi in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> r place ka use in this o restore the i operablc speci icatioa, "type of ubber(s) to 0 RABLE ~

snub er" shall mean tatus and per orm aa sn bcrs of the same engineeriag c aluation d ign and manufac rcr, on the atta cd component respective of c acityo or declare e attached system ino erable and 2~

folla appropriate Limiting Condition Snubbcrs are ategorizcd statement for that system. as inacccss le or accessible uring reactor operation Each of these categori s (inaccessible and ac ssible) may inspe ed indepcnd tly acco ing to the s cdulc det rained by Tab e

4. .8-1. The v ual pection int al for each type of ubber shall be determin based upon the criteri provided in Table 4:6. -1 aad the firs iaspecti interval determi ed using this criter a shall be based upon c previous insp ction interval as est lishcd by the req ircmcnts in cffcct before amendmcat No. 183 BFH 3.6/4.6-15 IIILENOMENTNo, y 88 Unit 3 PAGE~OF

Visual inspectio shall verify that (1) e snubber has no visibl indications of Cease o layaired OPERABILI ~ (2) attachR s to the founda on or supporting struc re are functional, and 3) fasteners for the at chment of the snubber t the component and to the ubber anchorage are functional. Snubbers which appear inoperable as a result of visual inspections shall be classified unaccep able and aay be reclassif d acceptable for e purpose of establish the next visual insp ticm interva.

provided t (1) the cause of the r ection is clearly establi ed and reaedied for t particular snubber and or other snubbers ir spective of type that be generically susceptible; and (2) the affected snubber is functionally tested the as-found conditicm detezained 0 per Specification 4 .8.5.

reviev and ev uation shall be perforae snd docuaented to gustif continued operatio with an unacce able'snubber. If ccmt ued operation cannot be Justified, the snubber shall be declared inoperable and the LINZTIEC COHDITIOKS FOR OPERLTIOK shall be aet.

BP5 3. 6/4. 6-16 AMENDMENrND. Z 8g Unit 3 PAGE 9 pp /g

4 6 8 Bmhhern 4.6.8.3 (Cont'd) kd tionall , snubb rs a tached sectio of afety-r ated s teaa that have erience unexpected poten illy d iag tr eats s ce the ast ins ection riod 11 be ev lusted or the ssibili y of c cealed e func onally tested conf i if OPB app cable, to LITT.

Snab ers vhi have be sad inoper le as th re t of expected t ansien , isolat aaage, r other oa events when the rovisions of 4. .8.7 and .6.8.8 ve be met and other ap opriate rrectiv a ion 1ap1 ented, 1 ot be co ted in deterain the n t visual inspect a

interv 1.

BFH 3 '/4.6>>17 AMENOMBfTNO. I8 3 Unit 3 PAGE~oF~S

4.6.8.

4.

Daring ch refue ng outage a repres tative aaapl of lOX the total of e ch type aa ty-relat snubbera in e in the ant shall be unctional teated either in place r in a ben teat.

The re eaentativ aLRple aele ed for fun ional tes ng shall 1 elude the va ious confi rations, o crating en ironILenta, and e range o size and capacity snubbers ithin'he type . The repres tative s pie should e veigh d to inclu e aore ubbers frc seve e aervi e areas such aa ear he equfpaent.

The atro e setting the aecuri of fastener for atta ent of the bbera to e coaiponent to the anu ber anchorag shall be ve fied on anu era selected for CTIOKAL TESTS'FR 3.6/4 6-18

~

em0mHrHU X83 Qnit 3 PAGc~oF

4.6.H. S u e 5.

snubber CTIOHhL ST shall v rify that:

a. Activ ion (restr ning

=acti ) is achie d in oth tension and co pression vi in the ecified r e, except hat inerti dependent, accelerati limiting mechanic snubbers may be test to verify only t at activation takes place in bot dir tions of trav l.

b. S ubber bleed, r elease where equired, is present i both compression and tension within the specified range+

c. For me ical snu ers, the rce require to ini ate or mai ain mo ion of the ubber is t great eno to verstress e attached piping or omponent during t rmal movem t, or to i icate imp ing failur of the snu er.

d. For nubbers sp ifically re ired not t displace er continu load, he ability f the snubbe to vithst load vithout displacem t shall be verified BFH 3.6/4.6-19 NENDMENT NO. 134 Unit e Ga~l'r~8' 3

0' 4.6.8.

4.6.H.S (Co?Lt'd e Testing methods may be used to mLcasurc p raactcrs indirectly or aactera other than sc spccif ic if those ed correl suits to the can be aye iad parameters ough established aethoda.

6 X~a&a tel ka engineeri evaluation shall be de of each failure to ecc e PUECTIOKAL TEST acce ance criteria to d I%inc the cause of the ailure. The result of this analysis shall be used if applicable, in aele snubbera to be t ted in the subsequent lo an effort to deterainc OPERhBILIIT of other an era which say be sub/a to the aaae failure Selection of snubbera r future testing aalu also be aaed on the failure analysis. For each ubber that does not aee the lUKCTIOML YES acceytance criteria, ddltional lot equal to yercent of the reaa r of that type of snub ra shall bc functi ly tc ed Tcsti?Lg s ontinue until no itional inoperable anu era are found within suba cnt lots or all snubbcrs the original tUKCTZ TEST type have bean i

teat or all suspect ambbers identified by the failure analysis have been teated, aa apylic able.

BFS 3 6/4.6-20 NENOMENT N. y 83 Unit 3 l8' pAG <~Ocean

19 1989

~ 6 oHo 'gt~

4.6.H.6 (C d)

If any snubber ected for functi testing either ils to lockup or ls to move, i.e.,

ozen in place, the caus will be evaluated and if caused by manufac er or design defici y, all snubbers the same desig bject to the s defect shall be ctionally tested.

This testing requirement shall be independ t of the requireme stated above for bbers not meetin e FUNCTIONAL TES cceptance criteria.

e discovery of loose or missing attachment fasteners will be aluate to determine w er the cause may b ocalized or generic e result of the luation will be u to select other suspect snubbers verifying the achment fasteners, applicable.

7 ~

r the snubber(s ound inoperable, gineering evaluation all be perform ed on the c ponents which are restr ned by the snubber(s The urpose of this e ineering evaluat shal 1 b o determine ifhe e compone nts restrained b NENDMQPNP Zeg BFN 3.6/4.6-21 Unit 3 PAGE~~~P~

cTS 3.4.

'JAN 19 1"-P

.6.H. ~~~s 4.6.8.7 (Co d) snubber(s) vere ersely affected by e inoperability of the s ber(s), and in order to re that the restrained co onent remains capable of ecting the designed ice.

8.

S ubb s Snubbe vhich fail the visual insp tion or the CTIONAL TEST accepta e riteria shall be re red or replaced. Rep cement snubbers and s hers vhich have repair hich might affect t FUNCTIONAL TEST result shall meet the FUN OHAL TEST criteria b ore installation i he it. These snubb s shall have met the ac sub quent to their ptance'riteria most rec service, and the FUNCTIO TEST must have been rformed vithin 12 mo before being ins led the unit.

C 0 Pe ent or other exemptions fr visual inspections d/or functional testing for individual snubbers y be. granted by the C ission if a Justifiable exemption is esented and asis for if applic e snubber life destruc ve testing vas rformed to qualify s ber OPERABILITY for e applicable design conditions at either the

~ J BPN Unit 3 3.6/4.6-22 NENDMENr NK X ac pAgE OF

CVg Z.6 JAR i9 1988 4.6.H. ~t~

4.6.H.9 (C 'd) completion of thei fabrication or a subsequent date. Snu rs so exempted shall c inue to be listed in t plant instructions with f tnotes indicating th extent of the exemp ns.

10. S e ora The se ce life of snubbers may e extended based on aluation of the rec s of FUNCTIONAL TESTS, maintenance his ry, and environment conditions to vhich the nubbers have been osed.

AMENOMENT NQ. X3 BFN 3.6/4.6-23 Unit 3 pwaa~~o>~~:

Cl 0

mrs .c.a/v<.e JAN I 9 1989 THIS PAGE IHTEHTIOHALLX LEFT BLAHK ANENOMENT Ng. X'3 BFH 3.6/4.6-23a Unit 3 PAGE~6'F~~

Table 4.6.8-1 SHUBBER VISUAL IHSPECTIOH IHTERVAL Populati Col A Column B Coluan C or Cate ry Extend terval Repeat Interval Reduce Interval 0

Hote 1: The next visual ection interval fo a snubber population category size sha be deterained bas upon the previous inspection inte al and the amber unacceptable snubbers found during t interval. Snubb s aalu be categorized, ased upon their ac essibility during er operation, as aces ible or inaccess le. These categori s aay be exaained sepa tely or /ointly Heaver, the lic ee auat aake and docua t that decision efore auy inspecti and shall use that de sion as the baai upon which to dete e the next inspecti interval for category.

Hote 2: Inte lation between po ation or category siz s and the n er of unacceptable ubbera is peraissible. Use next'lower in cger for the value f the liait for Col t integer includes a fractional value of A, B, or C cceptable if ubbers as detera d by interpolation.

Hote 3: If the nuaber of cceptable snubbers is equal to or lese than the nuaber in Co A, the next inspect on interval cay be tvice the previ interval but not gre ter than 48 aonths.

BPH 3 6/4.6-23b AMENDMENT N, g 83 Unit 3

Table 4.6.8-1 (Continued)

SSUBBER VISU ISSPECTI05 I hL If e nuaber of cceptable snub rs is equal o or less nenber i the number in Colum B but g eater than Co umn k, the nex inspection in erval shall b the saa as e previous int rval.

f the nuaber f unacceptabl anubbera ia e to o .greater than the n~ r in Column C the next inap ction in rval shall be tv thirds of the revioua inte al. Ho@ er, nuaber of cceytable bere ia leaa the if er in the Column C, t greater the member Golda, the next interval 1 be reduc proporti by int rpolation, that is, the previous terval ahall e reduc by a facto that is one-third of e ratio of e differ ce between e nuaber of unaccepta e anubbera fo dur the previo inte al and the n er in Column to the ifference the n~ rs in Col B and C.

yrovfakoma f Specificati 1 O,LI re applicab for all inspection int rvala up to including 48 aontha.

O'I 3 6I4.6-23c NENOMEgr gp. y 88

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.9 - RCS PRESSURE AND TEMPERATURE (P/T) LIMITS MINIST TIVE Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and by plant operators as well as other users. The therefore,'nderstandable reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

~ A~ These surveillances are a duplication of the regulations found in 10 CFR 50 Appendix H. These regulations require licensee compliance and can not be revised by the licensee. Therefore, these details of the regulations within the Technical Specifications are repetitious and unnecessary. Furthermore, approved exemptions to the regulations, and exceptions presented within the regulations themselves, are also details which are adequately presented without repeating the details within the Technical Specifications. Therefore, retaining the requirement to meet requirements of 10 CFR 50 Appendix H, as modified by approved

'he exemptions, and eliminating the Technical Specification details that are also found in Appendix H, is considered a presentation preference which is administrative in nature.

A3 For clarity, the terms "prior to and during startup" and "prior to" have been replaced with "15 minutes". This Frequency is effectively the same since the proposed Surveillance now must be performed no more than 15 minutes prior to startup of the idle recirculation loop. This is essentially equivalent to the current requirements.

I BFN-UNITS 1, 2, 8E 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.9 - RCS PRESSURE AND TEHPERATURE (P/T) LIHITS A4 Proposed SR 3.4.9.4 requires verification that the difference between the reactor coolant temperature in the recirculation loop to be started and the RPV coolant temperature are within 50 F of each other. CTS 3.6.A.6/4.6.A.6 requires verification that the temperatures between the idle and operating recirculation loops are within 50 F of each'ther.

The temperature of the "operating recirculation loop" is considered e equivalent to the RPV temperature. Therefore, this change is considered administrative.

Proposed SRs 3.4.9.5, 6 5, 7 require the reactor vessel flange and head flange temperatures be verified > 82 F, while CTS 4.6.A.5 requires the reactor vessel shell temperature immediately below the head flange be recorded. The BFN procedure that implements this requirement requires the vessel flange and head flange temperature be verified and requires the shell temperature be recorded. Since the intent of the surveillance is to verify vessel flange and head flange temperature to satisfy CTS 3.6.A.5 and both the current and the proposed SRs do this, the two are considered equivalent. As such, the proposed change is administrative.

TECHNICAL CHANGE - NORE RESTRICTIVE A new Surveillance Requirement has been added. SR 3.4.9.2 ensures the RCS pressure and temperature are within the criticality limits once within 15 minutes prior to control rod withdrawal for the purpose of achieving criticality. This is an additional restriction on plant operation.

H2 Three new Surveillance Requirements have been added. SR 3.4.9.5 ensures the vessel head is not tensioned at too low a temperature every 30 minutes. SRs 3.4.9.6 and 3.4.9.7 ensure the vessel and head flange temperatures do not exceed the minimum allowed temperature. These are additional restrictions on plant operation since the current requirements have no times specified.

M3 ACTIONS have been added (proposed ACTIONS A, B, and C) to provide direction when the LCO is not met. Currently, no real ACTIONS are provided. These ACTIONS are consistent with the BWR Standard Technical Specification, NUREG 1433, and are additional restrictions on plant operation.

BFN-UNITS 1, 2, 5 3 Revision 0 PAGE~OF~

JUSTIFICATION FOR CHANGES BFN ISTS 3.4.9 - RCS PRESSURE AND TEMPERATURE (P/T) LIMITS TECHNICAL CHANGE - LESS RESTRICTIVE "Generic" LAl Details of the methods for performing Surveillances, and any, requirement to record data, are relocated to the Bases and procedures. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in Chapter 5 of the Technical Specifications. Changes to the procedures will be controlled by the licensee controlled programs.

"Specific" Ll The Frequency of this Surveillance has been changed from 15 minutes to 30 minutes. Verification that RCS temperature is within limits every 30 minutes when RCS pressure and temperature conditions are undergoing planned changes is reasonable in view of the control room indication available to monitor RCS status. Also, since temperature rate of change limits are specified in hourly increments, 30 minutes permits a reasonable time for assessment and correction of minor deviations. In addition, this new Frequency is consistent with the BWR Standard Technical SP ecification, NUREG 1433.

'I L2 The Frequency of this Surveillance has been changed from 15 minutes to 30 minutes. The metal temperature is not expected to change rapidly due to its large mass, thus a 30 minute Frequency is adequate. In addition, this new Frequency is consistent with the BWR Standard Technical Specification, NUREG 1433.

BFN-UNITS 1, 2, & 3 Revision 0

0 t Rl The CTS

'ELOCATED SPECIFICATIONS

-

JUSTIFICATION 3.6.B/4.6.B -

FOR CHANGES COOLANT CHEMISTRY chemistry limits are provided to prevent long term component degradation and provide long term maintenance of acceptable structural conditions of the system. The associated surveillances are not required to ensure immediate operability of the reactor coolant system. Therefore, the requirements specified in current Specification 3.6.B/4.6.B did not satisfy the NRC Final Policy Statement technical specification screening criteria as documented in the Application of Selection Criteria to the Browns Ferry Unit 2 Technical Specifications and have been relocated to plant documents controlled in accordance with 10CFR50.59.

Revision 0 PAGE

JUSTIFICATION FOR CHANGES CTS 3.6.G/4.6.G - STRUCTURAL INTEGRITY RELOCATED SPECIFICATIONS Rl The structural integrity inspections are provided to prevent long term component degradation and provide long term maintenance of acceptable structural conditions of the system. The associated inspections are not required to ensure immediate operability'f the system. Therefore, the requirements specified in current Specification 3.6.G/4.6.G did not satisfy the NRC Final Policy Statement technical specification screening criteria as documented in the Application of Selection Criteria to the BFN Unit 2 Technical Specifications and have been relocated to plant documents controlled in accordance with 10CFR50.59.

BFN-UNITS I, 2, 8L 3 Revision 0 peCiE~OF~ '

JUSTIFICATION FOR CHANGES CTS 3.6.H/4.6.H - SNUBBERS TECHNICAL CHANGE - LESS RESTRICTIVE "Generic" LAl Snubber inspection requirements are part of the BFN Inservice Inspection (ISI) Program and are being relocated to the ISI program documents.

Requirements for the ISI Program are specified in 10 CFR 50.55a to be performed in accordance with ASIDE Section XI. NRC regulations contain the necessary programmatic requirements for ISI without repeating them in the proposed BFN ISTS. Changes to the ISI Program are controlled in accordance with 10 CFR 50.59. With the removal of operability requirements from the Technical Specifications, snubber operability requirements will be determined in accordance with Technical Specification system operability requirements.

BFN-UNITS 1, 2, 5 3 Revision 0

Section 3.4, Reactor Coolant System (RCS) Bases The Bases of the current Technical Specifications for this section have been completely replaced by revised Bases that reflect the format and applicable content of the proposed Browns Ferry Unit 2 Technical Specification Section 3.4, consistent with the BWR Standard Technical Specification, NUREG 1433. The revised Bases are as shown in the proposed Browns Ferry Unit 2 Technical Specification Bases.

BFN-UNITS 1, 2, Ea 3 PAgp evi sQF~

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

C 1 SpE'Cgi QLQo ., )

4 0 NOV 22 l988 LI TIHC COHDITIOHS FOR OPERATIOH SURVEILLAHCE REQUIREMEHTS 3.5 4,5 0 G Applies o the operational Appli to the surv llancc status of the core and reqair cats of the rc and containmen cooling systems. containm t cooling s terna when the corre pending limi ng condi-tion for o cration is i effect.

To assare the OP ILITY of To verify the PERABILITT of the the core and conta ament cooling core and contai cnt cooling systems under all c nditions for systems under al conditions for which thf.s cooling c pability is which this cool capability is an essential respons to plant an essential response to plant abnormalities abnormalities.

L,CD 1. The CSS shall be OPERABLE: 1. Core Spray System Testing.

3iS.l (1) PRIOR TO SI'JLBTUP Ll C IlI

~i~u~c from a COLD COHDITIOK> or SR ax.l"i a- Simulated Once/I8~,

Automatic Oyera&ag (2) when there is irradiate rage CC ~ '4 Actuation fuel in the vessel + SR3eS I J test and when the reactor vessel prcssure SR3~ 6b. Pump OPERA- Per Specifi-is greater than BILITY cation 1.0.MM atmospheric prcssure, except as specified in Specification 3.5.h.2 Co Op Val tor rate e

Per atioh, l. ~

Sycc+i-OPE ILI 5g P,S,],6 d. System flow Once/W rate: Each loop shall dclivcr at least 6250 gpm against a system head corres-ponding to a BFH 3.5/4.5-1 ~

Unit 1 AMENDMENTNO. 15 9 FA+', sF t5

I S fcc,'0'c~k'on 3.S. l AUG 02 t989 105 psi 5'4 differential B.S.i. 4 prcssure bctveen the ~

reactor vessel and the primary containment.

c hal V ve er ccif cati n MM S'g P f l.2..

2~ If one CSS loop is inoperable, Verify that Once/

+Cog)a) the reactor may remain in each valve operation for a period not to (manual, povcr-exceed 7 days rov /t5 operated, or Aires a ac ve components in automatic) in the the other CSS loop and thc infection flovpath RHR stem that is not locked, csc rs scaled, or other-e OPERAB vise secured in position, is in gL/ Sc >'n /Node 3 its correc g7 in Iahr positione

3. If Specification 3.5.A.l r 2~ Eo Idigio s+gl~e Specification 3.5.A.2 c ot r ited RCIToN bc met, the reactor shal be 84 H'laced in the COLD SHUTDOWH COHDITIOH vithin ho s. Sc'c X~l'*echo~ ger Agre'>>

S6 ca SPH tsTS S.t.l

4. Shen the reactor vesse pressure is atmospheric and irradiated fuel is in the reactor vessel at least one core spray loop vith one OPERABLE pump and associated Except that an automatic diesel generator shall bc valve capable of automatic OPERABLE, except vith the return to its ECCS position reactor vessel head remove vhen an ECCS signal is s ccific prcscnt may be in a as position for another mode spccificd in 3.5.A.1. of operation.

SCe 34SHCfca4o~ P,~ fjgggS BvH isis y,s.~ PAGE~OF~

BFH 3 '/4,5-2 Unit 1 hMENDMENTNO. 16 9

L.l AI4l oi The RHRS shall be OPERABLE fP. I. a. Simula ted O ce/,s Automa tie (1) PRIOR TO STARTUP Actuation from a COLD Test CONDITION; or 3 SRZ.S.t S b. Pump OPERA- Per

2) when there is BILITY Specification irradiated fuel in 1.0.

the reactor vessel and when the reactor C~ Motor Opera- Per vessel prcssure is ted 'valve Specification greater than OP ERAB ILITY 1.0.MM atmospheric, except as specified i' GRAS.I 4 d- Pump Flow Once/9 Specifications 3.5.B.2 Rate mes4hc ou h 3.5.B Test Check Per Valve Specification l.O.MM c/e 5g35 i g fO Verify each valve that cc (manual, power- s operated, or automatic) in the injection flow-path that is not locked, sealed, or otherwise secured in posi-tion, ig i correct position. Zld~w SR3,.S,I.V g. Verify LPCI ce/

subsystem cross-tie valve is closed gull power removed f rom

'R 3.5.l.g /4oK valve operator.

Low pressure coolant injection Ex ept hat an (LPCI) may be considered OPERABLE a orna c val e during alignment and operation apab of a to-for shutdown cooling with reactor mati retu to its steam dome pressure less than ECC posit on w en 105 psig in HOT SHUTDOWN, if an CCS s gnal is capable of being manually pr sent y b in realigned and not otherwise a posit n fr an her inoperable. ode of o e tio BFN 3.5/4.5W AMENOMENT gg, 2Pg Unit 1 PAGE

~k'cia'~Hen P,S; /

AUG 02 tGGG s RS.XI 2~ Vith thc reactor vcsscl Each LPCI pump shall deliver pressur less 105 psig, 9000 gpm against, an indicated the may be emoved system pressure of 125, psig.

from s rvicc ( cept hat tvo Tvo LPCI pumps in thc same RHR p ps-cont en cooling loop shall deliver 12000 gpm mode d asso atcd eat agaiast an indicated system cx ers t r ia pressure of 250 psig.

OPE ) fo a pe iod not to exceed hour vhile 2. An air test oa the dryvcl b dra ed of aad torus headers and nozzles s press n cham er qu ity shall be conducted once/5 vatcr fille vith years. A vater test may bc primary coolaa quali y performed on thc torus hcadcr vater rovide that ring in lieu of the air test.

coold vn tvo oops th o e pump er lo or o loo Se'e 3usRFicogon P<

vith tvo p ps, an QQQC'5 gi BFN associate diesel ~5'4'ig generatorsy ia e core ray stem are OPE

3. If e RHR um (LPCI mode) is inoperable, the reactor

~ may remain in operation for a period not to exceed 7 days r cma AcT>NJ pumps (LPCI mode) and both RHR H access paths of the RHRS LPCI made) and the CS 5 CC Su5AQ<a~~ At Ch~g

&~ BFu tSTS Z,S,l PERABLE.

Ll

4. If 2 RHR um s (LPCI Qei mode) become inoperablc, the reactor shall bc placed in the CO SHUTDOWH COHDITIOH vithin hours.

3'c.

Jn Noh' ia l2hrs Rnol

-a.-L~ne~g BFH Unit 1 3.5/4.5-5 NENDMENTNO. 16 9 I

0 Qpccl gicahon 3,5; )

8. If Specifications 3.5.B.1 t

thro h are ACT loQ5 B 4H. an e reac or inMQs 3 shall be placed in the COLD SH within WN CONDITION hours.

"~5

~q Sec'& Cicahora M~S7>> 4w 8p J4

~

l5TS $ .%

Pb LZ, When e 9. When the reactor vessel pressure is atmospheric and pressure is atmospheric, irradiated fuel is in the the RHR pumps and valves reactor vessel, at least one that are required to be RHR loop with two pumps or two OPERABLE shall be loops with one pump per loop demonstrated to be OPERABLE shall be OPERABLE. The per Specification 1.0.MM.

diesel generators pumps'ssociated must also be OPERABLE. Low pressure coolant injection (LPCI) may be considered OPERABLE during alignment and operation for shutdown cooling, if capable of being manually realigned and not otherwise inoperable.

10. If the conditions of 10. No additional surveillance Specification 3.5.A.5 are met, required.

LPCI and containment cooling re not required When there xs irradiated fuel 11. The RHR pumps on the in the reactor and the reactor adjacent units which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall be. demonstrated to be associated heat exchangers and OPERABLE per Specification valves on an adjacent unit 1.0.MM when the cross-must be OPERABLE and capable connect capability of supplying cross-connect is required.

capability except as specified in Specification 3.5.B.12 below. (Note: Because cross-connect capabi.lity is not a short-term requirement, a component is not considered inoperable if cross-connect capability can be restored to service within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.)

BPN 3.5/4.5>>7 NEHOMENT NO. 204 Unit 1 PAG~

1989

12. If one RHR pump or associated. 12. Ho additional surveillanc heat exchanger located required.

the unit cross collILectio the ad)a t unit is i operable fo any reason (i eluding val e inoperability, pip break, etc , the reactor may emain in op ation for a eriod not exceed 30 day provided remaining RHR pum and associ ed diesel generato are OPE

13. If RHR cro s-connection lov or 13. Ho additional surveillance heat remov capability lost, re uired.

the unit may remain in ope tion for a period t to exceed 10 days unless su capability is btoredo SC B.S..

14. 1 reci culati n pump 14. All recirculation pump di charge valves shall discharge valves shall be P PRIOR TO be tested for OPERABILI.

S (or close if during any period of permi ted el ether gg p g (,S COLD SHUTDOWH COHDITIOK in the speci cations) exceeding 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, if OPERABILITY tests have not been performed during the preceding 31 days.

BFK 3.5/4.5-8 Unit 1 AMENDMBlr80. y 69 PG 7 oF Is

SF'c; 'on 3. 5. I 4.9.4.4. (Cont'd) 5 c r~s+,'<'mt'on Q~ Ce The loss of voltage and degraded voltage relays C4+eS @r vhich start thc diesel l ~TS .St.cHon 3.3.g. ( gcncratora from the 4-kV shutdown boards shall be calibrated annually for trip and reset and the measarcmcnts logged.

These relays shall be calibrated as specified in Table 4.9.k.4.c.

St. 4 Sus+4 ta fjon 5a~c's foe BFn) d. '4-kV a own board lSTs 3.V. 7 voltages shall be recorded once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

5. Logic Systems 5. 480-V RMV Boards ID and 1E SR 3,5.l. l? LCt ~i%

a. Coamon accident signal ao Once c 0$

logic system is OPZRhBLE. e automat c transfer feature for 480-V RNOV boards ID and 321 shall be

>NSti Acegy~ P fanctionally tested to Qe BC'N )Sy> Z,~,l g verify auto-transfer capability.

b, 480-V load ahedd

,logic system is OPERJUKE.

6. There shall be a minimum of 35,280 gallons of diesel fuel in each of the 7-day diesel-gcncrator fuel tank assemblies.

5~< ~+if':nk'en fv Chr~

X+A) f5'Q jf g NENOMEHT Ng. y8g BPS 3 9/4.9-7 Unit 1 PAGE oF I~

$ Pcc,i4 '.5'. 1 NOV 0 4 199t 3.9.h.

See Yustihcation far Changes

d. The 480-V shutdown boards 5r at=~ 1sT',g,7 lh and 1B are energized.

e. The units 1 and 2 diesel auxiliary boards are ized

f. Loss of voltage and degraded voltage relays

~Ce Su544icaHon

& so~ isis Par z.z.Li f/~

OPERhBLE on 4-kV shutdown boards h, B, C, and D.

g. Shutdown buses 1 and 2 5CC ScaS+kcce'gase Qg Q/IongeS'~

energized. BFN isaac p,g,~

h. Th react r mo or-op rated valve RMO b ards & 1E are ener ized, th m tor-ge era r ( )

ets I, 1D > and lEh se ice

4. The three 250-V unit batteries, 4. Undervoltage Relays the four shutdown board batteries, a battery charger a. (Deleted) for each batte an assoc ated battery board are h. Once every 18 conchs, OPERhBLE. the conditions under which the loss of voltage and degraded voltage See g~gqg;cab'on f r Qaga W relays are required shall BPH 1575 3.f.g a~d 'tt.7 be simulated with an undervoltage on each shutdown board to demonstrate that the associated diesel generator wi'll start.

PAGE BFH 3.9/4.9-6 AMEHOMEHT tbtO I8 6 Unit 1

NOV 18 1888

12. When one 480-V ahutdovn See X~5+pjc'Phon 5c Chants fee board is found to be ZEOPERhBLE, the reactor l5 TS B.f 7 vill be placed in HOT STANDBY COHDITIOS vithin 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and COLD Q93TDO OIITI01 vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

13. If e 480-V ard ag se is proteid ZEO REk R 0 05 tinue for a eriod t o exce sev days the eaa 480-V ard sets and ir so cia lo 0

4. Zi aag 480- RMV aS sets ecoa Z50 rea tor

~ I shall COLD S vithin 24 pla CO urs.

in the TIO

5. If the reqaireaents for operating, in the See 345 hPicggon for (4~gy coaditioas specified by 3.9.B.1 through 3.9.B.14 t))-"H )S) S Sac@an ).E cannot be aet, an orderly shutdovn shall be initiated and the reactor shall be in the COLD SHUTDOWNS COHDITIOK vithin 24 hours.

PAGE Cn pP l5 BFN 3.9/4.9-14 Unit 1 AMENDMENT NO. y5 8

SPCC 4 'eA 3,5, FEB 0 7 I99I 3.5.D 0 s 4 ~ 5.D

1. The equipment area co er l. Each e ipme t area coole~

asso ated vith each is opera ed i con)unction pump the equipment vith the quip nt served area'coo r associated y that pa ticu r cooler; vith each t of core erefore, e e uipment spray pumps and C a a cooler are ested at or B and D) mu be the same freq ency s the OPERABLE at all mes pump vhich th se e.

en the pump or p s se ed by that speci c coole is considered t be OPE LE.

2. When an equ ment area cooler, is not PERABLE, the pump(s) se ed by that c er must be co idered inop ble for Tec ical Specific on purposes.

c.co 1. The HPCI sy em s all be HPCI Subsystem testing 3.s. ( enever there is . shall be. performed as irradiated fuel in the follovs:

reactor vessel and the +fu or Wr'f('CR4l ~7 reactor vessel pressure M3 S.(< r a. Simulated Once/18 (ll] is greater than 150 psig, copse( hloR Automatic months except in the COLD SHUTDOWH br sR3~(,'l Actuation COHDITIOH or as specified in Test 3 Specification 3.5.E.2.

OPERABILITY shall be deter-" Pump Per P(ep5eck ~ok mined vithin 12 hours after OPERA- Specification 4~ $R3,5,(,g reactor steam pressur (oA BILITY 1.0.

reaches 150 psig from a COLD COHDITIO r a ernat ve y c~ Moto Oper- Per RI TO ST P usi an ted alve Spe fica$ io 1 ry ste su ly. 0 RAB ITY .0.

Flov Rate at Once/4-a monQm sR 3,g.l,g ra or PI3 e

oe tng pr s re $ 2o& lolo(s,'g r~ SR (Oow s.s,(.q lg BFH 3.5/4.5-13

/t(Q AMENDMEHT NO. I S 0 Unit 1

Spec'4'<<a< 3',s, (

FEB 0 7 1991 Coolant In e sR z.s.>.8 Flov Rate at Once/18 psig months K /4S

+o'p The HPCI pump shall deliver Llo at least $ 000 gpm during each flow rate test.

ld ~s SR Verify that Once 3.5, i.w each valve R3 (manual, pover-operated, or automatic) in the injection flow-path that is not locked, sealed, or othervise secured in position is in its correc osition.

W 2 ~ If the HPCI system is inoperable, the react r may

~Bog // remain in operation d not to exceed M ays, a

prov ed t e R

<~re/ Qfioa p LPCI an S are OPERABLE. till~~

VCce P~

3~ If Specifications 3.5.E.l ~~

• E cept that an aut matic or 3.5.E.2 are not met, va ve c able aut mati retu to s

~

t e ECC posit on wh an reactor vessel pressure ~ac s ECCS ignal is pre ent shall be reduced to 150 may b in a ositio for or less vithin R4 '"'sig anothe mode o hours. 3& operation.

F. 'eacto Co e splat o Coo in F. Reactor Core Iso at o Cooli

~

1. The RCICS shall be OPERABLE 1. RCIC Subsystem testing shall whenever there is irradiated be performed as follows:

fuel in the reactor vessel and the reactor vessel a. Simulated Auto- Once/18 pressure is above 150 psig, matic Actuation months except in the COLD SHUTDOWN Test CONDITION or as specified in 3.5.F.2. OPERABILITY shall BFN e~ X~A;Rc ho< 4c'~~5 .5/4.5-14 NIENOMEMt Hp. X 80 Unit O'C 80% lSYS SaSo3 1

pAQF /~ QF~~~

SgeCig'ro,>on g, g.

NY 1 9 l994 Six valves of the Automatic Durin ea cretin Depressurization System c he following shall be OPERABLE: tests shall be performed on the ADS: L(

Ac~i Of (1) PRIOR TO STARTUP from SR P,g J lg a. A simulated automatic a COLD CONDITION, or, L actuation test shall ISb cut~ l8 ~55. be performed PRIOR '.

TO (2) whenever there is STARTUP te each Qqhcqb's)iQ irradiated fuel in the outa reactor vessel and the reactor vessel pressure f he relief gal s is greater than 485 ps g, is ove d except in the COLD SHUT- PAfaScd 4~ 4.6. .2 DOWN CONDITION or as 4 Sg g,S,ll )9$

specified in 3.5.G.2 and 3.5.G.3 below.

2~ With one of the above required al P'GTlodb ADS valves inoperable, E provided the HPCI system the recpaka ed-.

core spray system and the LPCI system re OPERABLE, res ore the inoperable ADS valve to OPERABLE statue within 14 days or be in at frig s+c( Sg 3,5 / 3 WTlog least a HOT SHUTDOWN CONDITION within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and 8+8 reduce reactor steam dome frofasect AcTloH p ressure to ~ 495 psig within hours. IS@

sc 3~ With two or more of the above required ADS valves R CTiDA5 inoperable, be in at least a G.

HOT SRJTDOWN CONDITION within i2 hours and reduce react steam dome pres'sure to g +95 psig within hours. ISo 3'4, L2, Rss~'rM Ps@on L) (LCo 3.s,gg QopB 2 cubi whig 7gry Old DE 3 QPifhirt (3/r L I's (W A~ <nlrb)

PlODE 9 luis n 3'7/lfS LI BFN 3.5/4.5-16 NENOMENT NL 2P g Unit 1 PAGE ~3 OF~5

S eCigca. 'on R,g 0KC O V 894 7

.C 6~C

2. Anytime irradiated fuel is in 2. With the air sampling the reactor vessel and reactor system inoperable, grab coolant temperature is above samples shall be 212'F, both the sump and air obtained and analyzed sampling systems shall be at least once every 24 OPERABLE. From and after the hours.

date that one of these systems is made or found to be inoperable for any reason, the reactor may remain in operation See Y~sSka Hen P, Cg~~

during the succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> W BPt4 ls75 g.q,g for the sump system or 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> I for the air sampling system..  !

!

The air sampling system may be removed from service for a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for calibration, function testing, and maintenance without providing a temporary monitor.

3. If the condition in 1 or 2 above cannot be met, an orderly shutdown shall be initiated and the reactor shall be placed in the COLD SHUTDOWN CONDITION within 24 hours. 4.e.D

1. Approximately one-hal of all relief valves

1. When more than one relief valve shall be bench-checked is known to be failed, an or replaced with a orderly shutdown shall be bench-checked valve initiated and the reactor each operating cycle.

depressurized to less than 105 All 13 valves will have psig within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The been checked or relief valves are not required replaced upon the to be OPERABLE in the COLD completion of every SHUTDOWN CONDITION. second cycle.

2. In accordance with 4

+~>4 "<wagon 4c SPA )sTs g~,~

CQ~ Specification 1.0.MN ach elie va ve shall be manually opened unt ermocoup es and Pfop6c'd a usti monit s

~ a4 do stre of t e val e

~ S.S.i. U ind cate earn i ow fro the ve.

LR BFN 3.6/4.e-lo AMENPlHEHT NL 2 Z3 ~3 Unit 1 PAGE 1 QF I5

Rig~

SC S.S.<,1 Whenever the core spray s stems, e following surveillance LP I, HPCI, or C ired requirements shall be adhered to e OPERAB , th discharg to assure that the discharge pipi from the pum discharg piping of the core spray of the e systems to t e last systems, LPCI~ HPCI, d RCI block v lvc shall be f led. are filled:

The suctio of the IC an 1. ve mont h pumps shall e aligned to the he RHRS LPCI and condensate storage tank, and Conta ament Spray) and core the pre ure supp ession chambe spray system, the dischar head tank shall no lly be pipin of these s stem Pll aligned to erve the discharge v ed om e h'gh oin piping of th RHR and S pumps.

Th condensate head t wa fl d rm ed may be used to serve th RHR an CS 2. F ow ng any per od where the disc ge piping the P hea LP I or ore s ray s t tank i unavailable The hav not een r quire to e pressur indicators the OP LE, he di charg pi ng discharg of the RHR CS of t ino rable syst sha 1 pumps sha indicate not less be v ted f m the high in than liste below. prior o the eturn of the system o service.

Pl-75-20 48 psig Pl-75-48 48 psig 3. Whenever the HPCI or RCI Pl-74-51 8 psig system is lined up to take P1-74-65 48 psig suction from the condensate storage tank, the dischar e pipin of thc HFCI an CIC bc v n p t ft s t ob rve on a monthly S~c ~~ f 'cabin f c Chavez)a basis.

f4'~~ )STS 3,g.y 4. en th RHRS and th CSS are r uired o be OPERAB , the pr sure x dica ors whx h mon shall or th disc arge be mon tore daily li es d the pressure recor ed.

PAGE~OF L +

BFN 3 '/4.5-17 AIENOlHENT No. 2 05 Unit 1

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP

5 ce Sic 4io~ '3 ~ ~

4 0 0 COO G S S S p ) NOV 22 1988 LIMITIHG COHDITIOHS FOR OPERATION SURVEILLAHCE REQUIREMENTS 3.5 CO CO COO G 4.5 'O CO COO G MSHXILS ~SS~~S cab cab t A lies to the operational Applies to the s eillance st us of the core and requirements of th core and coat ament cooling systems. containment cooling ystems vhea the corresponding lim ting condi-tion for operatioa is effect.

0 ect ve 0 ect vc To assure the OP ILITY of To ve fy the OPERABILITY of the thc core and conta cnt cooling core an containment cooling systems under all co itions for systems er all conditions for vhich this cooling cap ility is which this ooling capability is an essential rcsponsc to lant an essential zesponse to plant abnormalities. abnormalities.

ca o Sec cto t 3.5. l ahe (1)

CSS from a shal1 be PRIOR TO STARTUP COLD CONDITION~

OPERABLE:

or there is irradiated sR 3.s.l.g 1.

a.

Core Spray System act Ao lated Automatic Actuation Testing.

g~v~enc cc]e Qpomtekag 4ppl;((4'.Ig <>> rhea P,l gQ tle4, fuel in the vessel *sea.s,l. t test and when thc reactor P3 p"t vessel pressure f Pump Opera- Pcr Specifi-is greater than PRIES I bility catioa 1.O.MM atmospheric pressure, except as specified c. otor Per pec fi-in Specification Op ated n~en l.h MN 3.5.A.2.

O pg Valv OPERABILITY san.s.l.(, d. System flov Once/M ~P'~

rate: Each loop shall deliver at /

qz. 4~s least 6250 gpm against a system head corres-ponding to a BFH 3.5/4.5-1 Unit 2 AMENDMEHTNO. 15 5

g gC,,'fir.qC(o~ ~ < I ON

'

~ S Cont'd) 105 psi g.s.t. 6 differential pressure bctveen the reactor vessel and the primary containment.

P~ e. Ch ck Valve Per Speci cati a.o.m 20 If one CSS loop is inoperable, Once/

PA'ld 9 .the reactor may remain in each valve operation for a period not to (manual, pover-exceed 7 days rovidi operated, or all active components in As automatic) in the the other CSS loop and thc ~ection flovpath PCI mode that is not locked, and the diesel generators sealed, or other-are OPERABLE. vise secured in position, is in Sc w Ho~ its correc p7 IR Qrg position.

3~ If Specification 3.5.h.l or addit nal s~eQ lance Ad riOat Specification 3.5.h.2 cannot is r ire

~+8 be met, the reactor shal e placed in the COLD SHUTDOWH COHDITIOH vithin hours. 74 s4iflc44s ~ ~ Col4<<wg+J LQ. g4~ a~~ (srs ~.s.~

4, When thc reactor vesse pressure is atmospheric and irradiated fuel is in the reactor vessel at least one core spray loop vith one OPERJQKZ pump anil associate4 ccpt that automatic diesel generator shall be v ve capable f autom tic OPERABLE, ezcept vith the re rn to its CS posi ion reactor vessel head remo vhen ECCS sign is c ln 3.5.A. or presen may be in a PRIOR TO STARTUP as position or another mode specified in 3.5.h.l. OA6 of operation.

+~~~>4 t,'cA(d~ 4yi Qd~

• - gS/ Is~ ~

PAGE~QF~5 BFH 3. 5/4. 5-2 Unit 2 16 9 AMENDMENTNO.

nme t ent oo xng The RHRS shall be OPERABLE 0. l. a. Simulated ce >g Automa tic Opee~Ig

) PRIOR TO STARTUP Actuation Oyer from a COLD Test CONDITION; or S~ ~ < l g b. Pump OPERA- er

2) when there is BILITY 'pecification irradiated fuel in 1.0.MM the reactor vessel and when the reactor c. otor pere- er vessel pressure is ted valve Specxf xcatxon greater than OPERABIL atmospheric, except as specified in Sg S.5, ).C d. Pump Flow Once/&

Specifications 3.5.B.2, Rate 6 through 3.5.B.7.

e. Testa e Per Check Specification A~ Valve 1.0.MN 5R 35I.'L f Verify that Once/04m+h each valve (manual, po~er-operated, or J/ cg automatic) in the injection flow-path that is not locked, sealed, or other~isa secured in pcsi-tion, i in its P'7 correc positron. 81

g. Verify LPCI nce/

subsystem cross-tie valve is closed nruj power removed from valve operator.

sR 3.</.2. So@.

Low pressure coolant injection Except t >at an (LPCI) may be considered OPERABLE automat c valve during alignment and operation capabl of auto- '

for shutdown cooling with reactor mati return to steam dome pressure less than ECC position en 105 psig in HOT SHUTDOWN, if an CCS signa is capable of being manually present may ve in realigned and not otherwise a position for another inoperable. mode of operation.

3.5/4.5-4 AMENPMgfT gg. 22P Unit 2

S ci fic~A~w 3.5. I AUG 02 5gg 34 ~

nt ainment 0 0 ~ )

sR 3.S.

2~ With the rea tor vessel ach LPCI pump shall deliver pressure le than 105 psig, 9000 gpm against an indicated the RHRS' be removed system pressure of 125 psig.

from serv ce (except that tvo Two LPCI pumps in thc same RHR pump -containment cooling loop shall deliver 12000 gpm mode associated heat against an indicated system exch ers must remain pressure of 250 psig.

OPE LE) for a per d not to ceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> hile 2. An air test on the dryvell b ng drained of and torus headers and nozzle ppression ch er quality shall be conducted once/5 vater and primary cool filltd quality vith years. h vater test may be performed on the torus header vater provi ed that dur in lieu of the air test.

cooldown o loops wi one pump per oop or one oop vith tvo pumps, an See: a'aA4<J>o associated diesel generators, in th core c < g~~ imam r.C.2 s ra s stem a LZ Lf 3~ If one RHR ump (LP mode) Pl ~ e PcTI0 hl is inoperable, the reactor A may remain in operation for a period not to cxcecd 7 days rov e e rema n ng p,cgw pumps (LPCI mode) and both H access paths of the LPCI mode an S an s$ :AcJ o- 4'-

S,ea Cw~(~~

t c cse generators remain Sir BFN la~ <. S. l OPERABLZ l~

4. If 2 umps (LPCI ance mode) become inoperable, the reactor shall be placed in thc COLD SHUTDOWN CONDITION vithin hours.

3b

$ 2.

plo6 3 is. /2 4rS BFN 3 5/4.5-5 ~(.-E~OF lP Unit 2 AMENDMENTNO. l6 9

m Pi 4 tainmen t inmen t

8. If Specifications 3.5.B.1 nce Acvlo~ l2 6w COLD SHUTDOWN CONDITION Sce ~~s]A'zi4~ 4r within hours. C4o~igg ger Bf'N

<S~) Rr.~

esse 9. When the reactor vessel pressure is atmospheric and pressure is atmospheric, irradiated fuel is in the the RHR pumps and valves reactor vessel, at least one that are required to be RHR loop with two pumps or two OPERABLE shall be loops with one pump per loop demonstrated to be OPERABLE shall be OPERABLE. The per Specification 1.0.MM.

diesel generators pumps'ssociated must also be OPERABLE. Low pressure coolant injection (LPCI) may be considered OPERABLE during alignment and operation for shutdown cooling, if capable of being manually realigned and not otherwise inoperable.

0. If the conditions of 10. No additional survei'lance Specification 3.5.A.5 are met, required.

LPCI and containment cooling are not required When there is irradiated fuel 11. The RHR pumps on the in the reactor and the reactor adjacent units which supply is'ot in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall be demonstrated to be associated heat exchangers and OPERABLE per Specification valves on an adjacent unit 1.0.MM when the cross-must be OPERABLE and capable connect capability of supplying cross-connect is required.

capability except as specified J in Specification 3.5.B.12 below. (Note: Because cross-connect capabili.ty is not a short-term requirement, a component is not considered inoperable if cross-connect capability can be restored to service within 5 hours.)

3. 5/4. 5-7 AMENDMENT HD. 223 Unit 2

5'c i'gic<4io AUG 02 198S va S ent

12. If three RHR pumps or associated heat exchangers located on the unit cross-connection in the ad)acent uni s are operable for any r son

( ncluding valve inopc bility, pi e break, etc.), thc r ctor may emain in operation for a eriod not to exceed 30 day provided the remaining RHR pump and associated diesel generator are OPERABLE.

3. If RHR cross connection flov or 13. No additional sur illance heat removal pability is lost, required.

the unit may re ain in operation for a period not o exceed 10 days unless such c ability is restored gg 3.5.(,5

4. 11 rec rcu at on ump 14. 411 recirculation pump d

bc charge ERABLE vcs sh IOR TO ll discharge valves shall bc tested for OPERABILITY STAR (or cl clscv scd if uring any period of permit d re sq q~ ~ COLD SHUTDOMH CONDITION in these specifi tions).

~

exceeding 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, if OPERABILITY tests have not been performed during the preceding 31 days.

3.5/4.5-8 AMENDMENT NO; 169 Unit 2 WGE

S ec',f<e 4'.S.

NOV 0 ~ 1991 TZOH A> HTS 4

d. The 480-V shutdown boards 2A and 2B arc energized. See ~~xlP+lw cog r g- gem ic.rs 3.8.7

e. The units 1 and 2 diesel auxiliary boards are energized.

f. Loss of voltage and-degraded voltage relays see ~~sligicPaw 4l c4~Jag OPERABLE on 4-kV shutdown boards A, B, C, and D.

~ PpN Ic7s 2.3.8.J

g. Shutdown buses 1 and 2 S e ~us4Ki~k.o. 4r n.-g~

energized. 4< NFL Isis 3.8.J The 480 reactor motor-opera d valve ( OV) boar s 2D & 2E e encr ized wi motor-gen ator g) s s 2DH, 2D , 2EH, d 2EA service.

The three 250-V unit batteries, 4. Undcrvoltage Relays the four shutdown board batteries, a battery charger a. (Deleted) for each battery and ssociatc atte board arc b. Once every 18 months, OPERABLE. thc conditions under which the loss of voltage and degraded voltage relays arc required shall be simulated with an undervoltagc on each shutdown board to demonstrate that the associated diesel generator will start.

3.9/4.9-6 AMENDMgfTN0, $ 9g

4.9.h.4. (Cont'd)

c. The loss of voltage and degraded voltage relays which start the diesel QQ, 3~gle ksc41 >~ generators from the 4-kV

~ shutdova boards shall be phag~ Qr LJ calibrated annually for f5+/ 5CC4 l~ ~ 3 8'I trip and reset and the meaaurcmenta logged.

These relays shall be calibrated aa specified

.h.4.c.

cc 4~L4i4<ce4 4t 4-kV shutdown board C~~ T'5 QI- gP'tJ voltages shall be recorded once every.

J S 3.8.7 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

5. 480-V RNOV Boards 2D and 2E 5 Logic Systems I5 ~is.

a. Comaon accident signal ~P logic system ia OPERABLE. e aut c transfer feature for 480-V RMDV boards 2D and 2E shall bc functionally teated to verify auto-transfer capability.

b. 480-V load shedding, logic system ia OPERAS.

6. There shall be a miniaaun of 35,280 gallons of diesel fuel in each of the 7-day diesel-generator fuel tank assemblies.

See r~k l;o <~. Ch.Zc~

~ gin irrs R,Z.3 NEHDMEHT NO. 1. 9 I BES 3.9/4.9-7 Unit 2

. )s

L

. Whea onc 480-V shutdovn board is found to be IHOPERABLE, thc reactor vill be placed in the HOT STAIBY COHDITIOH vithin 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and COLD SHOTDOWH COHDITIOH vithin 24 hours.

13. If onc 48I PERABLE, V RNOV board mg set is REACTOR POWER 0 ERATIOH may cont e for a period not to cccd seven daysg pr ided the rema 0-V RMOV board sets and their associa ed loads remain OHGKBLE

4. If auy tvo 4 0-V RMOV board mg s s become IHOPE , the rea or shall placed in c

~ I 15.

COLD S vithin 24 If WH CO hours.

ITIOH thc requirements for operating in the conditions specified by 3.9.B 1 through 3.9.B.14 cannot be mct, an orderly

+C 4av ZML4iC+g~

QpW

~ ~h~g I S7 5 shutdovn shall be 5~~Qy~ p g initiated and the reactor shall be in the COLD SHUTDOWH COHDITIOH vithin 24 hours.

BFH 3 '/4.9-14 Unit 2 AMENDMENT NO. Zg 4 0 OF f5 pAGE

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~ ~ I ~ ~ ~ ~ I ~ ~ ~

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r

Cl S'

5'iVi'cc4io~ 3.R /

FEB 0 7 t9gt ct on SR S~ Flov Rate at Once/18 448-psig months c (45 P sip The HPCI pump shall deliver Io at least 5000 gpm during each flov rate test.

SR f ~ Verify that Once/

E.C. I. 2 each valve (manual, pover-operated, or automatic) in the injection flov-path that is not locked, sealed, or othervise secured in positio , is in its correc position.

2 ~ If the HPCI system is inoperable, the reactor may remain in operation for a period not to exceed ~ pcyio~

I days, rovided the As Pro RHRS(LPCI and RCICS Ahviog are~OP LE D vtr nc 3 ~ If Specifications 3.5.E.l

• ept that au automatic or 3.5.E.2 arc not mct, va e capable o autom tic p,n iota retu to its EC posi on g4H t e

~o PE vhen a ECCS signa is reactor vessel pressure present y be in a shall be reduced to 150 position or another mode psig or less vithin of operation.

3'ours.

a o o F. a t C 0 oo The RCICS shall be OPERABLE 1. RCIC Subsystem testing shall vhenever there is irradiated bc performed as follovs:

fuel in the reactor vessel and the reactor vessel a. Simulated Auto- Once/18 pressure is above 150 psig, matic Actuation months except in the COLD SHUTDOWN Test CONDITION or as specified in 3.5.F.2. OPERABILITY shall 3.5/4.5-14 AMENDMEHT NO. 190 BFN Unit 2 Sec Z~>$;~iicqfjo~ 4~ C~ra egal ]g7g 5 5'3

FEB 0 7 199t

1. Six valves of 1. Duri each operat the Automatic c c 0 ov ng p,g Depressurisation System tests shall be performed shall be OPERABLE: on the ADS 4'R (1) PRIOR TO STARTUP a. A simulated automatic from a COLD COHDITIOH, 3 5.( lO 'ctuation test shall or, be performed PRIOR TO I (Vg~+ STARTUP er eq p )~Q~ (2) vhenever there is (5 ~rg. efuel c irradiated fuel in the rve ~cc reactor vessel and the o the rel val&s reactor vessel pressure is vercd i is greater than si 4.6.D.

except in the COLD SHUT- Pro~ Ny DOWH COHDITIOH or as W s~

specified in 3.5.G.2 3.s. I. LQ and 3.5.G.3 belov.

2~ Pith one of thc above e ances required ADS valves inoperablc, provided the P,neo& HPCI s stem, e core P ~~~ sf 3.s;],g spray system and the LPCI stem re OPERABLE, restore the inoperablc ADS valve to OPERABLE status vithin 14 days or bc in M least jEcTlo 4 a HOT SHUTDOWH CO5QITIOH 9 o(-+ Ace(ou r=

e~H vithin thc next lg'nours and reduce reactor team dome pressure to sig vithin hours. ISO 3~ Vith tvo or more of the above required ADS valves, inoperable, Pcyso nE be in at least a HOT SHUTDOWN

& COHDITIOH vithin 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor team dome pressure to sig vithin hours. 58 b L.5 R4'g ~ ~M Ackiy- g. I (C Z u 3.~)

Robe 2- 1,~'7 ggg vf< I34 s A J7 I rs~g.lZ BFH 3.5/4.5-16 Unit 2

A DEC 0 7 l994 G COND 0 S OR 0

.6.C Coo age 4.6.C Co a a 2~ Anytime irradiated fuel fs in 2. With the afr sampling the reactor vessel and reactor system inoperable, grab coolant temperature fs above samples shall be obtafned 212 F, both the sump and air and analyzed at, 1cast sampling systems shall be once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

OPERABLE. From and after the CC date that one of these systems I is made or found to be inoperable for any reason, thc reactor may remain in operation durfng the I succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the S~< +'S Ja 4 C J.; ~ CO/'M O gag I4 I sump system or 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for fo~ SPV'i<7-S ~.q.g the afr sampling system.

The afr sampling system may be removed from service for a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for calibration, function testing j and maintenance vithout providing a temporary monitor.

3~ If the condition in l.or 2 above cannot be met, an orderly shutdovn shall be initiated and the reactor shall be placed fn the COLD SHUTDOWNS COHDITIOS vithfn 4s6 D 24 hours.

Approximately one-half o f all relief valves shall be bench-checked or When more than onc relief replaced vith a valve is knovn to bc failed, bench-checked valve each an orderly shutdovn shall be operating cycle. All 13 inftiated and thc reactor valves vill have been 4eprcssurfzed to less than 105 checked or replaced upon psig vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The the completion of every relief valves are not required second, cycle.

to be OPERABLZ in the COLD SHUTDOWN 20 In accordance vith Speci cation 1.0.

IR 'I .S. I . LI rclicf valve shall Sec ~,t;g;<;

W QFIIJ IS~

P,C<

P.Q.3

~ be manually o ened unt ermo coup es OJo4. ~ ac tic monitors Sa 3.s.l. II do earn of valv indicat steam is loving f c8 from thc valve.

3.6/4.6<<10 AMENbMENT NO. 2 29 BPÃ Unit 2 P GE~

5 ci4ica4iom 3.5. (

AU 0 1989 3.5. 4~ s e

~ ~

~a &

S g 3.C'. l. 1 Whenever the core spray systems, The folloving surveillance LPCI, HPCI, or RCIC required requirements shall bc adhered to be OPERABLE, the disc to assure that the discharge pipi from the pump disch ge piping of the core spr of th e systems to the las systems, LPCI, HPCI, d RC C block lve shall be filled. are filled:

g.A 7 The sucti of the IC an 1. Every month pumps shal be aligned to the t e RHRS (LPCI and condensate s orage tank, and Containment Spray) and core thc pressure ppression chamber spray system, the discharge head tank shall ormally be aligned piping of these systems sha 1 to serve the dis arge piping of e volte rom t hig po~t th RHR and CS pum s. The and vat flov detc ined con sate head t may be used 443 to s e the RHR and S discharge 2. Fo ov ng any period vhere pipin if thc PSC head tank is unav lable. The pr sure t LPCI or core spray systems hav not been r uired to be indicato on the discha e of the OPE LE, the di harge, iping RHR and CS umps shall in cate of th inoperable stem hall not less th listed belov. be vent from the igh point prior to the return of the Pl-75-20 48 psig system to service. LA9'.

Pl-75-48 8 psig P1<<74-51 48 psig Whenever the HPCI or RCIC Pl-74-65 48 psig system is lined up to take suction from the condensate storage tank, thc discharge piping of the HPCI and RC s c ve e rom the gh poin f thc s stem had vater flov obse d on a monthly basis.

""<~~~< bio gr Z4w- ~ 4. When the RHRS and the CSS are

$04 gag IgyS r uired to bc PERAB the pre ure indicat vhic monit thc dischar lin shall be monitored daily and thc prcssure recorded.

OBFH 3. 5/4. 5-17 AMENDMENT tltO. I6 9 Unit 2

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

8 CO COO ~ z. i MQV 22 1988 4.5 00 G MIXER kppli.es the opcrationa lies to the surve lance status of e core and rcq rements of thc co e and containmcnt cooling systems. conta ent cooling sys when thc cor cspondipg limiti condi-tion for peration is in e feet.

To assure the 0 LITT of To veri the 0 ILITY of thc the core and containm t cooling core and conta t cooling systems under all cond iona for systems under all onditions for which this cooling capab lity is which this cooling pability is an essential response to ant essential response to plant abnormalities. abnormalities.

t aco 3 5'-(

1. The CSS (1) shall be OPKHBLE:

PRIOR TO STARTUP from a COLD COHDITIOK, or SR s.s.).g l.

ao Core Spray System Testing.

c+

Simulated Automatic Once/Q ~

Q&44LC441g 9

(2) when there is irradiate Actuation 4p6kc Ayl'cab' '4) fuel in the vessel Pn~sed ]u. > teat and when the reactor + see.s..

vessel pressure b. Pump OPBM- Pcr Specifi-is greater than Rg sg p.g,>,L BILITX cation 1.0.

atmospheric pressure, except aa specified in Specification

c. ~

otor 0 eratcd r Spe ifi-ca on 1 O.MM 3.5.k.2. V ve ILIA

d. System flow Once/& 8Z rate: Each m~?$

loop shall sZZc.l. ( deliver at least 6250 gpm against a system head corres-ponding to a PAGE BFH 3.5/4.5-1 Unit 3 NENDMENTNO. t> O

Ci

+F1 f 105 psi

'diffcreatial 3 5 J ~ (

prcssure betvcea the reactor vehsel and the primary containment.

e. stable Per Che Valve Qpecifi tioa I.O.NN 5 3.5- .> A3

2. If one CSS loop is inoperable, Verify that the reactor may remain in each valve operation for a period aot to (manual y povcr-exceed 7 da rov ng operatcd, or 1 active components in Bs automatic) in the iqC+ie ~ H the other CSS loop and th inJection flovpath RHR stem CI mod that is not locked, e dicsc generator sealed, or othcr-are OPERABLE. vise secured in position, is in its oottsotg-Qyl 6c in hloge3 position.

ZH I&bras

3. If Specification 3.5 h.l or additi~sotssiLLanos Specification 3.5.k. cannot is ired.

PC4'o nJ be met, the reactor shal be 8+ placed in the COLD SHOTDOWE H

COHDITI05 vithin hours. 5cc ~~gg;ecch'oit Qc change 3C, L2, ~r Se+ ISV'S r,S, I

4. en the reactor vessel pressure is atmospheric and irradiated fuel is in the reactor vessel at least one core spray loop vith one OPERABLE pump and associated Except that an automat c diesel generator shall bc valve capable o autom ic OPERhBIZ, except vith the r turn to its EC posit on reactor vessel head remove vh aa ECCS signa is as s ecificd in 3 h. r prcscn may bc in a a position for another mode specified ia 3.5.h.l Scc gusttg ~ fio~ + chcln)cf rr BAN ISTIC 3.5.2 BFH 3,5/4.5-2 Unit 3

g,l qua I ~k The RHRS shall be OPERABLE 8. &o Simulated Once/ iB,s Q2. Automatic ~aking PRIOR TO STARTUP Actuation Qcc1s-from a COLD Test CONDITION; or

b. Pump OPERA- er Applicab Iig (2) when there is BILI~ Specification irradiated fuel in 1.0.MM the reactor vessel and when the reactor c~ Motor Opera- Per vessel pressure is ted valve Specification greater than OPERABILITY 1.0.MM atmospheric, except as specified in s83.5, l. 0 Pump Flow Once/W J Specifications 3.5.$ .2 Rate men ths- 4ag through 3.5.B 7.

e. Testable Per Check Specification Va,lve 1. MM Sg 3.S.I.Z Verify that Once/

each valve (manual, power-operated, or automatic) in the injection flow-path that is not locked, sealed, or otherwise correc

'n its secured in posi-tion, position.

7 oR PC~:~y ~ mme~~g~

St~keff valve i~

Verify LPCI subsystem cross-Once/

tie valve is LPC( crust g,'t ts c4scd closed ~

removed from power

~C 3. S. l. Z Nsa valve operator.

Low pressure coolant injection Except that an (LPCI) may be considered OPERABLE auto tic valve during alignment and operation cap le of auto-

'or shutdown cooling with reactor ma ic retu to ts steam dome pressure less than CS posi on en 105 psig in HOT SHUTDOWN, if an ECCS igna is capable of being manually present may be in realigned and not otherwise a position for another inoperable. mode of operation.

BFN Unit 3

3. 5/4. 5-4 NENOMEMT HO. I 77

i 0

skci4 ca~n a.s.

SURVZnumCE REqUIZZmm UB 02

~ ~ ~

~R 2~ With the reactor csscl Each LPCI pump shall deliver prc sure less t 105 psig, 9000 gpm against an indicated th RHRS may b removed system pressure of 125 psig.

f om service except tvo Two LPCI pumps in the same pumps-c tainmcnt ooling loop shall deliver 12000 gpm mode and a ociated h at against an indicated system exchanger must r prcssure of 250 psig.

OPEiULB for a pc od not to cxc d 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> vhilc 2. hn air test on the drywell being drained o and tyne headers and nozzles supp cssion ber quali y shall bc conducted once/5 va r and fi ed vith years. k vatcr test may be p ry coo t quali performed on the torus header vatcr prov ded that d ing in es cooldovn o loops v th one See Zff5t)fi'Gabon &I pump pe loop or o loop Chases vith pumps, ~c SP'iV (5 Tg g,g, g.q associ tcd diesc generators, in e core spray system a e OPBRhBLE.

3~ If ne RHR um (

1 I mode)

.

+5'o 4 is inoperable, the reactor may remain in operation for a period not to excccd 7 days prov e e rema pumps (LPCI mode) and bo access paths of the LPCI mode and the S and Sea $~,1'C'cJitsrS f. I a ors rema in gyral 3 OPE

4. If any' RHR ecome um (LPCI inoperable, the mode reactor shall be placed in the COLD SHUTDOWH COHDITIOH vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3C Bc,;r e&e3, in Izhrs pAGE 5 oF~~

BFH 3. 5/4. 5-5 Unit 3 hMENGMBlTNO. t a O

Cl nt ent

8. If Specifications 3.5.B.l through 3.5.B.7 are not met, Ron5 8+' 'a44keted d the reactor shall be placed in the R in~<3 A1 Sec JuSt 4>'capon COLD SHUTDOWN CONDITION '~ IPhrs Per Changes gr gP~

within hours. ts rs s.s.~

3 When e reactor vessel 9. When the reactor vessel pressure is atmospheric and pressure is atmospheric, irradiated fuel is in the the RHR pumps and valves reactor vessel, at least one that are required to be RHR loop with two pumps or two OPERABLE shall be loops with one pump per loop demonstrated to be shall be OPERABLE. The OPERABLE per diesel generators pumps'ssociated Specif ication 1.0.MM.

must also be OPERABLE. Low pressure coolagt injection (LPCI) may be considered OPERABLE during alignment and operation for shutdown cooling, if capable of being manually realigned and not otherwise inoperable.

10. If the conditions of 10. No additional surveillance Specification 3.5.A.5 are met, required.

LPCI and containment coolin are not requi d When there is irradiated fuel The B and D RHR p'umps on in the reactor and the reactor unit 2 which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall be demonstrated to associated heat exchangers and be OPERABLE per valves on an adjacent unit Specification 1.0;MM when must be OPERABLE and capable the cross-connect of supplying cross-connect capability is required.

capability except as specified in Specification 3.5.B.12 below. (Note: Because cross-connect capability is not a short-term requirement, a component is not considered inoperable if cross-connect capability can be restored to service within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.)

AMENDMENT NQ. g 77 BFN 3.5/4.5-7 Unit 3 pgsp~oF~t~

8 AUG 02 t989 on

12. If one RHR pump or associated located heat exchanger on the unit cross-connection in unit 2 is i perable for any reason ( eluding valve inopcrabilit pipe eak, etc.), the rc tor ma remain in operation for a eriod not to excee 30 days rovided thc remai RHR pump d associated diese generator a OPERABLE.

3~ I cross-co ction flov or 13. Ho additional surveillance heat emoval capabi ty is lost, required.

thc un t may remain i peration for a pe od not to exce 10 days unless such capability is restored. SR XS.

14. h rec rculat n p 14. All recirculation pump ischarg valves shal discharge valves shall b OPERAB PRIOR 0 be tested for OPERABIL ST (o closed f during any period of pe tted e cvhere COLD SHUTDOWR COHDITIOH in t se spe ficatio ).

gg 3~t~ exceeding 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, if OPERABILITY tests have not been performed during thc preceding 31 days.

BFH 3.5/4.5-8 AMENDMENTHO. I4 0 Unit 3 PAG<~

S Stoic I g(

ggt'EB i 4 1995

<chion 4.9.A.4. (Cont'd)

Sc< 3'us,H f-: Qe, c. The loss of voltage ckclwy g and degraded I ST 5 Section 3' voltage relays g ( which start the diesel generators from the 4-kV shutdown boards shall be calibrated annually for trip and reset and thc measurements logged. These

~ca >u~S'6;c tt'nnA, relays shall be 0 ng c5 g ~ p~ (et calibrated as l STS Z87 specified in able 4.9.A.4.c.

d. 4-kV shutdown board voltages shall bc recorded once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

5. 4 -V V pard 3Rk2E

a. Accident signal logic system is OPERABLE. sC r.s.i.u. a. Once c automatic

b. 480-volt load s e transfer feature logic system is OPERABLE. for 480-V RMOV boards 3D and 3E

>ee 3<5(inca fjin far shall bc

~'~ (sTS S.g.(

~go functionally tested to verify auto-transfer capability.

6. There shall bc a minimum of 35,280 gallons of diesel fuel in each of the 7-day diesel-gcncrator fuel tank assemblics.

5ea Ri

$ wy;p;a.4on Qr ~~

pFg BPS 3 ~ 9/4 ~ 9-7 AIItEHDMEÃfRtt. I8 9 Qnit 3 PAGE 8 'oF ~~

8

,

NOV 0 4 1991

e. Loss of voltage and degraded voltage relays OPERhBLE on 4-kV shutdown boards 3Eh, 3EB, 3EC, and 3ED.

f. Thc 480-V diesel Sec. s ~ << "~~ L'4~)~)

auxiliary boards 3Eh and 3EB are encrgizcd. 4-~ Be< (sr> s.s.7

g. The 480-V reactor tor-opera d valve

( V) boards 3D Ec 3E arc ergized th motor enerator )

sets 3D 3Dh, 3ES, and 3Eh in service.

4. Thc 250-V shutdown board 4.

3EB battery, all three unit battcriea, a battery a. (Delctcd)

! charger for each battery, and associated battery b. Once every 18 months, )

boards arc OPERhBLE. the conditions under which the loss of voltage and degraded voltage relays are regni,rcd shall Sc4 >~ski((ek,oe fur be simulated with an C44 pg undervoltage on each cfor OP~ (pre g ~ q shutdown board to deaoastrate that thc associated diesel generator will start.

>< 3uStigi'agon SPu fir Cfu~eS ~

IST5 s BPS 3.9/4.9W pAGE~AMENlpjp~TN 1 5 8 Unit 3

. SPe.c.,g;~I'on Z.5. l S S 1%lOV 18 1988 PERA

10. When one 480-V shutdown board is found to be inoperable, the reactor WStjCicah'on 4r Changing vill be placed in HOT ~r BAN I$ 75 P. g,-7 STANDBY CONDITION vithin 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and COLD SHUTDOWH OHDITIOH within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

11. If on 480-V RMOV board g set s inoperab e, REA OR PO OPERATIO may co inue for perio not to exceed se en days p ovided th remain ng 80-V RMOV board sets and their associa d load remain 0 ERABLE.

12 If any tvo 480- RMOV board sets ecome inop abLe, t e react r sha be pla ed in t e CO SHUTDO CONDI OH vithin 24 h urs.

13. If t e r cerements or operation in the conditions specified by SeC g>~>.;~Hon 4. Cg~~CS 3.9.B.1 through 3.9.B.12 cannot be met, an orderly

+ ~ON I ST~ SecAen Xg shutdovn shall be initiated and the reactor shall be in the COLD SHUTDOWH CONDITION vithin 24 hours.

'MEtf0t,1ENT M. ypg BFN Unit 3 PAGE~OF

11 FEB P 7 t991 3 ~5 ~ 4.5.D u

1. The equipme area cooler E h equipment rea cooler associated vi h each RHR is crated in c unction ump and the e uipment vith e equipment erved a ea cooler ass ciated by that articular c oler; vi each set of core therefore the equipm t spra pumps (A an C area coole are teste at or B d D) must b the same fre ency as th OPERAB at all tim umps vhich th serve.

vhen the ump or pum OPERABLE'.

served by hat specif cooler is c sidered be t

2. en an equipme area coo er is not OPE LE, the p p(s) served y tha cooler ust be consi ere inoperabl for Technical Specificati purposes.

C Co The system shall be HPCI Subsystem testing OPERAB enever there is shall be performed as I irra ated fuel in the fo vs+

ky);cubi l $

) reactor vessel and the +al or reactor vessel pressure ~S~.~r a. Simulated Once/18 is greater than 150 psig, Automatic months except in the COLD SHUTDOWH PropoSed hk K Actuation CONDITION or as specified in 4r SR.g.g.l. Test pecification 3.5.E.2.

OPERABILITY shall be deter- b. Pump Per Prop seA mined within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> a te 5R~~t.g OPERA- Specification Alod Pr reactor steam pressure 4 oM BILITY .O.MM SR E.g.l,8 reaches 150 psig from a OLD CONDITION, r a t ely c. otor per- e PR R TO ST TUP b usi an a ed Va ve S cif cation aux iary ste sup y. OP RABIL Y 1.

d. Flow Rate at Once/W no a 5/P 3.5. I .1 rect r 3 v s 1 kz.

op a ng pr s re Prcfo+g Qpg qco H l~/o.

~ ]

BFN 3.5/4.5-1 PlO AMENDMENT tl0 152 Unit 3 ls

0 on 3 So t FEg 0 7 )99t

~ ~

R z.s.l,g e.

~Flow Rate at psig The HPCI pump Once/18 months shall Ps g deliver. at least 5000 gpm during, each flow rate test.

Verify that Once/Wm~

each valve 5R p.g.(.~ (manual, power-operated, or automatic) in the infection flow-l.'hov l4 path that is not locked, sealed, or otherwise secured in position, is in its correc osition.

A7 2~ If the HPCI s stem is inoperable, t e reactor may remain in ope ation f period not to exceed 'ys, provided the RHR tfo+std LPCI ICS are QCTTo& OPE LE er'.Ac z

~ cd iR Ic 1 't 3 ~ If Specifications 3.5.E.1 cept hat an automatic or 3.5.E.2 are not met, va ve ca ble of utomatic PtChor15 ret rn to ts ECCS osition the when an ECC signal s G-0 reactor vessel pressur prese t in H

shall be reduced to 150 '<<s positi may b for a a

other m de psig or less within 24-3g of opera ion.

ours.

L2.

F. R Co e solation Cooli F. Reactor Core Isolation Coolin t RC CS The RCICS shall be OPERABLE 1. RCIC Subsystem testing shall whenever there is irradiated be performed as follows:

fuel in the reactor vessel and the reactor vessel a. Simulated Auto- Once/18 pressure is above 150 psig, matic Actuation months except in the COLD SHUTDOWN Test CONDITION or as specified in 3.5.F.2. OPERABILITY sha BFN AMENDMENT NO. I5 2 Unit 3 Sr 8-8 l5T$ p.5 $

PAG~oF

1. Six valves of the Automatic 1. Durin each o crating k Depressurisation System cycl e following shall be OPERABLE: tests shall be performed on the ADS:

tooaL Or (1) PRIOR TO STARTUP from gg p g1 ~oa. A simulated automatic a COLD CONDITION, or, actuation test shall be performed PRIOR TO (2) whenever there is STARTUP a ter ~ch

<PP~o&'li'Q irradiated fuel in the refute.ng outa e.

reactor vessel and the nua surveys anc reactor vessel pressure o the bpliefgval es is greater than 485 psig, is over+ in g except in the COLD 4.6. .2.

DOWN CONDITION or as specified in 3.5.G.2 a 3.5.G.3 below. le ppapSC pie&

5 ~ Sa 3.S.l l~

2. With one of the aSove required

/kh'ons ADS valves inoperable, provided the H CI system, the

.gi core spray system and the LPCI syst are OPERABLE, s ore e inoperable ADS valve to OPERABLE status within 14 days or be in at least a HOT SHUTDOWN CONDITION Pcafo5cJ QcQoA F Algol within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce reactor s earn dome ressure to Z psig within ho s. ISb g.

3L

3. With two or more of the above required ADS valves ikhon inoperable, be in at least a HOT SHUTDOWN CONDITION within g 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reduce react steam dome pressure to g psig within hours.

~IW r

PC pO yA QI L5 R<oooor<d pioiion p,i pico 3.0.,3) t'ai t 4iA 7J)f5

~DC '3 Lo >thin l3 ~

~in: oi oooo~ n 3 i gon<s~i.i>

BFN 3.5/4.5-16 hNENOMENT NO. 178 Unit 3 ..;.;; tx .,-- (s

EC 0'7 1994 3.6.C 4.6.C Z. Anytime irradiated fuel is in 2. With the air sampling the reactor vessel and reactor system inoperable, grab coolant temperature is above samples shall be 2LZ'F, both the sump and air obtained and analyzed sampling systems shall be at least once every 24 OPERABLE. From and after the hours.

date that one of these systems is made or found to be inoperable for any reason, the reactor may remain in operation during the succeeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the sump system or 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for, thc air sampling system. >+c X~SWkimh on Q~ Ch~

6I ggp( )5 fg y q The air sampling .system may be removed from service for a period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for calibration, function testing, and maintenance vithout providing a temporary monitor.

3. If the condition in 1 or 2 above cannot be met, an orderly shutdovn shall be initiated aad the reactor shall be placed in thc COLD SHUTDOWN CONDITION vithin 4.6.D.

24 hours.

1. Approximately one-half 3.6.D. of all relief valves shall be bench-checked

1. When more thaa one relief or replaced vith a valve is kaovn to be failed, bcnchmhecked valve an orderly shutdovn shall bc each operating cycle.

initiated and the reactor hll 13 valves vill hav depressurised to less than lOS been checked or psig vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> The replaced upon the relief valves are not required completion of every to be OPERABLE in the COLD second cycle.

SHllTDOMN CQNDITIQN.

2. In accordance vith

<<<

4< 81-N l5T5 gag'R

~r;~yon g~ dtegCS

.g.]

Specification 1.0.%5 c relief valve shall be manually o cned ti t ermo oup e an a oust c mon tore kr~rct jar fC. do str am of hc ve "sR r.5.1. Ll ind cate stcam e lo ag f om the velvr BPÃ 3.6/4.6-10 ANENMOrr NL I 88 Unit 3 GOOF

~Pec, 'o ~-S-t NY 9 l994 sly.s;/.1 Whenever t core 8 ay systems, The following surveillance LPCI, HPCI, r RC required requirements shall be adhered to be OPERAB the dis ar to assure that the discharge piping from'he ump disc rge piping of the core spra these systems o the las systems, LPCI, HPCI, and RCIC bl ck valve shall filled. are filled:

The s tion of the P 1. Eve pumps s all be aligned o the e RHRS CI and condensa storage tank, and Conta nment Spray) and core t e press suppression amber spray systems, the dischar e hea tank s 1 normally b pipin of these systems shall align d to se the dischar e vened om /he h h pbjnt piping f the e cond and CS pump sate hea tank may be

~ d wattr fl w %term ed.

'us d to se e the aad CS 2. Following any period where the dis harge px ing if th PSC head I or core spray sy tems tank is unava able. Th have ot been equired o be pre88 e indica ors on th OPERAB the scharge p ing discha ge of the shall i and CS umps icate not less than of the ino erabl be vented f the system 8 ll m igh poin listed b ow. prior to the turn of e 8 8 tern 't Pl 0 48 p ig Pl-75-4 48 ps 3~ Whenever the HPCI R Pl-74-51 48 psig system is lined up to take Pl-74-65 48 psig suction from the condensate storage tank, the dischar e piping of the HPCI d RCI e vened from t high oint f the 8+tern and wate low observe on a monthly

>< Xsgg;mg.~Jr bas s.

Chu

@

P~ SFN ls T$ p.g.p en the RHRS and the CS are r uired to b OPERABLE, t pre ure indicat s which monit the discha lines shall be onitored da y and he pressu e recorded.

BFN 3.5/4.5-17 NENOMENTRO, r7g Unit 3 q+Z' ~

QWI

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.1 - ECCS - OPERATING ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

Five current LCOs, 3.5.A, 3.5.B, 3.5.E, 3.5.G, and 3.5.H, have been combined into one proposed LCO (3.5. 1). As such, the new LCO combines the three ECCS spray/injection Systems (HPCI, LPCI, and CS) into one LCO statement. The Bases continue to describe what components make up an ECCS subsystem. The new LCO statement also specifies that the six ADS valves are required. In addition, the ADS valve cycling requirements located in current Specification 4.6.D. 1 are included as part of ADS operability. Thus, if an ADS valve does not cycle, the affected ECCS system is considered inoperable and the appropriate ACTION taken.

A3 The Frequencies of "Once/operating cycle," "during each operating cycle," and "after each refueling outage" have been changed to "18

'onths." This is considered equivalent since 18 months is the length of an operating cycle or a refueling outage cycle. The Frequencies of "Once/3 months" and "Per Specification I.O.HM" have been changed to "92 days," or "In accordance with the Inservice Testing program" as appropriate. The IST program test frequency for pumps is every 3 months and is currently defined by Specification I.O.MM. Therefore, this change is considered administrative in nature. The Frequency of "Once/month" has been changed to "31 days."

A4 Notes allowing actual vessel injection or ADS valve actuation to be excluded from this test (simulated automatic actuation test) have been 0 added to proposed SR 3.5. 1.9 and SR 3.5. 1. 10.

BFN-UNITS 1, 2, 5 3 Since the current Revision 0 PAGE OF

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I

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.1 - ECCS - OPERATING I

requirements state the test is "simulated" (i.e., valve actuation and vessel injection are inherently excluded), this allowance is considered administrative in nature.

AS Proposed Condition H provides direction for various interrelationships between HPCI and ADS, and between LPCI and CS. The Action requires entry into LCO 3.0.3 for various combinations of inoperability which are consistent with the present required actions for the same various combinations. The actual requirements are not being changed.

A6 The existing Applicability for Core Spray System (CSS) Operability (3.5.A.1), and Low Pressure Coolant Injection (LPCI) Operability (3.5.8. 1), requires both systems to be Operable whenever irradiated fuel is in the vessel and prior to startup from a COLD CONDITION. The proposed change (LCO 3.5. 1 Applicability) requires them to be Operable in Modes 1, 2 and 3. This change more clearly defines the conditions when CSS and LPCI are required to be Operable without changing the specific requirements which are currently located in individual specifications for each system. This change is, administrative because the same requirements for Operability currently listed in specific specifications will be labelled APPLICABILITY and apply to the entire ISTS Section 3.5. 1, ECCS-Operating. The 3.5.A.2, 3.5.B.2, and 3.5.B.7 Applicabilities are only cross references and have been deleted.

A7 The clarifying information contained in the "*" footnote has been moved to the proposed Bases for SR 3.5. 1.2. The intent of the surveillance is to assure that the proper flow paths will exist for ECCS operation. The Bases clarifies that 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. As such, moving this clarifying statement to the Bases is an administrative change.

AS This requirement has been deleted since it only provides reference to another Specification, and does not provide any unique requirements.

The format of the proposed BFN ISTS does not include providing "cross references."

A9 Surveillance Requirements for HOV operability, and check valves that are required by the Inservice Testing (IST) Program, have been removed from individual Specifications. This change is considered administrative in nature since these requirements remain in the IST Program which is defined by proposed Specification 5.5.6.

BFN-UNITS 1, 2, 5 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.1 - ECCS - OPERATING A10 The flow tests for the HPCI System are performed at two different pressure ranges such that system capability to provide rated flow is tested at both the higher and lower operating ranges of the system.

Since the reactor steam dome pressure must be a 920 psig to perform SR 3.5. 1.7 and a 150 psig to perform SR 3.5. 1.8, sufficient time is allowed after adequate pressure is achieved to perform these tests. This is clarified by a Note in both SRs that state the Surveillances are not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the specified reactor steam dome pressure is reached. CTS 3.5.E. 1 already contains the context of the Note for the low pressure flow rate test. This is also consistent with interpretation of the current technical specification requirement for the high pressure flow rate test which is currently not modified by a Note.

All The existing Applicabilities for High Pressure Coolant Injection (HPCI)

Operability (3.5.E. 1) and ADS (3.5.G. 1) require the systems to be Operable whenever irradiated fuel is in the vessel and reactor pressure is greater than 150 psig (105 psig for ADS), except in the COLD SHUTDOWN CONDITION. The proposed change (LCO 3.5. 1 Applicability) requires HPCI and ADS to be Operable in Modes 1, 2 and 3, except when reactor steam dome pressure is < 150 psig. (Reference Justification L5 for the. change in applicability from < 105 psig to < 150 psig for ADS.) This change more clearly defines the conditions when HPCI and ADS are required to be Operable without changing the specific requirements which are currently located in the individual specifications. This change is administrative because the same requirements for Operability currently listed in the specific specifications will be labeled APPLICABILITY and apply to the entire ISTS Section 3.5. 1,,ECCS-Operating. The 3.5.E.2, 3.5.G.2, and 3.5.G.3 Applicabilities are only cross references and have been deleted.

A12 A finite Completion Time has been provided to verify RCIC OPERABILITY.

The new. time is immediately and is considered administrative since this is an acceptable interpretation of the time to perform the current requirement.

A13 CTS 3.9.A.3.h (for Unit 1 and 2) and 3.9.A.3.g (for Unit 3) require 480 V reactor motor operated valve (RMOV) boards to be energized with motor-generator (MG) sets in service. CTS 3.9.B. 13 and 14 (for Unit 1 and 2) and ll and 12 (for Unit 3) provide Required Actions for when one or any There are two 480-V AC RMOV two 480-V MG board sets become inoperable.

boards that contain MG sets in their feeder lines. The 480-V AC RMOV boards provide motive power to valves associated with the LPCI mode of the RHR system. The MG sets act as electrical isolators to prevent a BFN-UNITS 1, 2, 5 3 3 Revision 0 PAGE

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.1 - ECCS - OPERATING fault propagating between electrical divisions due to .an automatic transfer. Having an MG set out of service reduces the assurance that full RHR (LPCI) capacity will be available when required, therefore, the unit can only operate in this condition for 7 days. Having two MG sets out of service can considerably reduce equipment availability; therefore, the unit must be placed in Cold Shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The'nability to provide power to the inboard injection valve and the recirculation pump discharge valve from either 4 kV board associated with an inoperable MG set would result in declaring the associated LPCI subsystems inoperable and entering the Actions required for LPCI.

Since, the out of service times for LPCI and the MG sets are comparable, the deletion of the MG set actions is considered administrative.

TECHNICAL CHANGE - MORE RESTRICTIVE Ml Proposed Action H requires LCO 3.0.3 be entered immediately which requires the plant to be in MODE 2 in 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and MODE 3 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> when multiple ECCS subsystems are inoperable. This change is more restrictive because it stipulates that the reactor shutdown be completed much earlier than would be required by the existing specifications (CTS 3.5.A.3, 3.5.B.4, 3.5.B.8, and 3.5.E.3). For CTS 3.5.G.2 it is slightly more restrictive since it requires the plant to be in MODE 2 in 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> where no action was required before. CTS require a shutdown to NODE 4 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (except CTS 3.5.G.2 for ADS which also requires the plant be in NODE 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />) but does not stipulate how quickly MODE 3 must be reached. Reference Comment L12 which addresses the less restrictive change of being in NODE 3 in 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> versus 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and NODE 4 (or < 150 psig which is outside the applicability for ADS and HPCI) in 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> rather than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Surveillance requirement SR 3.5.1.3 has been added to verify that ADS air supply header pressure is z 90 psig. This is a new Surveillance Requirement which verifies that sufficient air pressure exists in the ADS accumulators/receivers for reliable operation of ADS. Since this is a new Surveillance Requirement, it is an added restriction to plant operations.

N3 With the reactor pressure < 105 psig, CTS 3.5.B.2 allows the RHR System to be removed from service (except that two RHR pumps-containment cooling mode and associated heat exchangers must remain OPERABLE) for a period not to exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> while being drained of suppression chamber quality water and filled with primary coolant quality water provided BFN-UNITS 1, 2, & 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.1 - ECCS - OPERATING that during cooldown two loops with one pump per loop or one loop with two pumps, and associated diesel generators, in the core spray system are OPERABLE. This appears to be an exception to CTS 3.5.A.2 8 3, which only allows one CSS loop (i.e., one loop with two pumps) to be inoperable for 7 days and an immediate shutdown if this cannot be met.

The ¹ Note for 3.5.B.1 allows LPCI to be considered OPERABLE .during alignment and operation for shutdown cooling with reactor steam dome pressure < 105 psig in HOT SHUTDOWN, if capable of being manually realigned and not otherwise inoperable. Proposed Specification 3.5.1 has a similar provision (Note to SR 3.5.1.2). Since the proposed Specification has no provision that would allow continued operation in MODE 3 with pressure <105 psig with two CS loops with one pump per loop OPERABLE, the proposed change is considered more restrictive.

M4 An additional requirement is being added that requires the plant to be in MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This change is more restrictive because it stipulates that the reactor shutdown be completed much earlier than would be required by the existing specifications (CTS 3.5.A.3, 3.5.B.4, 3.5.B.S, and 3.5.E.3). CTS require a shutdown to MODE 4 within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> but does not stipulate how quickly MODE 3 must be reached. Reference Comment L2 which addresses the less restrictive change of being in MODE 4 (or < 150 psig for HPCI and ADS) in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> rather than 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> s.

TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" LAl Not used.

LA2 The details relating to system design and purpose have been relocated to the Bases. The design features and system operation are also described in the FSAR. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in proposed BFN ISTS Section 5.0 and changes to the FSAR will be controlled by the provisions of 10 CFR 50.59. ECCS system operability determinations are described in the Bases. SR 3.5. 1. 1 will ensure maintenance of filled discharge piping.

BFN-UNITS 1, 2, & 3 Revision 0 PAGE jz

JUSTIFICATION FOR CHANGES BFN ISTS 3.5 ECCS - OPERATING LA3 Details of the methods of performing surveillance test requirements and routine system status monitoring have been relocated to the Bases and procedures.'hanges to the Bases will be controlled by the provisions of the proposed Bases Control Process in proposed BFN ISTS Section 5.0 and changes to the procedures will be controlled by the licensee controlled programs.

LA4 Any time the OPERABILITY of a system or component has been affected by repair, maintenance or replacement of a component, post maintenance testing is required to demonstrate OPERABILITY of the system or component. Therefore, explicit post maintenance Surveillance Requirements have been deleted from the Specifications. Also, proposed SR 3.0.1 and SR 3.0.4 require Surveillances to be current prior to declaring components operable.

LA5 CTS 3.5.D/4.5.D, Equipment Area Coolers, are being relocated to plant procedures. Relocating requirements for the equipment area coolers does not preclude them from being maintained operable. They are required to be operable in order to support HPCI, RCIC, LPCI and CS system operability. If they become inoperable, the operability of the supported systems are required to be evaluated under the Safety Function Determination Program in Section 5.0 of the Technical Specifications.

This change is consistent with NUREG-1433.

LA6 CTS 3.5.E specifically states that HPCI Operability can be determined prior to startup by using an auxiliary steam supply in lieu of using reactor steam after reactor steam dome pressure reaches 150 psig.

Details of the methods of performing this surveillance test requirement have been relocated to the Bases and procedures. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in proposed BFN ISTS Section 5.0 and changes to the procedures will be controlled by the licensee controlled programs.

LA7 CTS 4.5.H.l requires the discharge piping of RHR (LPCI and Containment Spray) to be vented from the high point and water level determined every month and prior to testing of these systems. The specific requirement to vent prior to testing has been relocated to procedures. Changes to the procedures will be controlled by the licensee controlled programs.

BFN-UNITS 1, 2, 8L 3 PAGE~OF~i;; 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.1 - ECCS - OPERATING "Specific" Ll The phrase "actual or," in reference to the automatic initiation signal, has been added to the surveillance requirement for verifying the ECCS subsystems/ADS actuate on an automatic initiation signal. This allows satisfactory automatic system initiations for other than surveillance purposes to be used to fulfill this requirement. Operability is adequately demonstrated in either case since the ECCS subsystems/ADS itself can not discriminate between "actual" or "simulated."

L2 The time to reach MODE 4, Cold Shutdown (for LPCI and CS) and < 150 psig (for HPCI and ADS) has been extended from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This provides the necessary time to shut down and cool down the plant in a controlled and orderly manner that is within, the capabilities of the unit, assuming the minimum required equipment is OPERABLE. This extra time reduces the potential for a unit upset that could challenge safety systems. In addition, a new (more restrictive) requirement to be in MODE 3 (Hot Shutdown) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been added for LPCI, CS and HPCI (Reference Comment M4 above). These times are consistent with the BWR Standard Technical Specifications, NUREG 1433.

A new Action (proposed ACTION 0) is being added to LCO 3.5.1 for the.

condition of an inoperable HPCI System coincident with one inoperable low pressure ECCS injection/spray subsystem. The analysis summarized in the current SAFER/GESTR-LOCA analysis (NEDC-32484P, February 1996) demonstrates that adequate cooling is provided by the ADS system and the remaining operable low pressure injection/spray subsystems. However, the redundancy has been reduced such that another single failure may not maintain the ability to provide adequate core cooling. Therefore, an allowable outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> has been assigned to restore either the inoperable HPCI system or the inoperable low pressure injection/spray subsystem to operability. This change is consistent with NUREG-1433.

L4 The allowable outage time for HPCI has been extended from 7 days to 14 days. Adequate core cooling can be provided by ADS and the low pressure ECCS subsystems. The 14 days is allowed only if all six ADS valves and the low pressure ECCS subsystems are operable. (The exception, LCO 3.5.1, Condition D, which allows operation for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with HPCI and one low pressure ECCS subsystem inoperable is addressed in Comment L3 above.) The 14 day Completion Time is based on the reliability study that evaluated the impact on ECCS availability (Memorandum from R. L.

Baer (NRC) to V. Stello, Jr. (NRC), "Recommended Interim Revisions to BFN-UNITS 1, 2, 5. 3 Revision 0 PAGE~GP~

0 JUSTIFICATION FOR CHANGES BFN ISTS 3.5.1 - ECCS - OPERATING LCOs for ECCS Components," December 1, 1975). Factors contributing to the acceptability of allowing continued operations for 14 days with HPCI inoperable include: the similar functions of HPCI and RCIC, and that the RCIC is capable of performing the HPCI function, although at a substantially lower capacity; the continued availability of the full complement of ADS valves and the ADS System's capability in response to a small break LOCA; and, the continued availability of the full complement of low pressure ECCS subsystems which, in conjunction with ADS, are capable of responding to a small break LOCA. This change is consistent with NUREG-1433.

L5 The pressure at which ADS is required to be operable is increased to 150 psig to provide consistency of the operability requirements for.HPCI and RCIC.equipment. Small break loss of coolant accidents are not analyzed to occur at low pressures (i.e., between 105 and 150 psig). The ADS is required to operate to lower the pressure sufficiently so that the LPCI and CS systems can provide makeup to mitigate such accidents. Since these systems can begin to inject water into the reactor pressure vessel at pressures well above 150 psig, there is no safety significance in the ADS not being operable between 105 and 150 psig.

~

\

L6 A new ACTION has been added (ACTION F), which allows an outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> when one ADS valve and a low pressure ECCS subsystem is inoperable. Currently, there is no allowed outage time when these two items are inoperable. The analysis summarized in the current SAFER/GESTR-LOCA analysis (NEDC-32484P, February 1996) demonstrates that adequate cooling is provided by the HPCI and the remaining operable low

'pressure injection/spray system. However, the redundancy has been reduced such that another single failure concurrent with a design basis LOCA could result in the minimum required ECCS equipment not being available. Therefore, an allowable outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> has been assigned to restore either the inoperable ADS.valve or the inoperable low pressure injection/spray system. This change is consistent with NUREG-1433.

L7 Current Technical Specifications only allow one LPCI pump to be inoperable. Proposed ACTION A allows two LPCI pumps, one per loop or two in one loop, to be inoperable for seven days. The BASES for ISTS 3.5.1 Required Action A.l state that the 7 day allowed outage time is justified because in this condition, the remaining OPERABLE subsystems t provide adequate core cooling during a LOCA. This justification is applicable for the LPCI function of RHR with one or two RHR (LPCI) pumps out of service as demonstrated by previous LOCA analyses performed for BFN-UNITS 1, 2, 8. 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.1 - ECCS - OPERATING BFN as well as the current SAFER/GESTR-LOCA analysis (NEDC-32484P, February 1996). Following postulated single failures, adequate core cooling can be provided by one loop of Core Spray (2 pumps) and two RHR (LPCI) pumps (either two pumps in one loop or one pump in two loops) in conjunction with HPCI and ADS. Therefore, this less restrictive change is acceptable based on the plant specific LOCA analysis perfqrmed for BFN.

L8 This change proposes to add a Note to current Surveillance Requirement 4.6.D.4 (proposed Surveillance Requirement 3.5. 1,12) which states, "Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reactor steam pressure and flow are adequate to perform the test." This change allows the Applicability of the Specification to be entered for 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> without performing the Surveillance Requirement. This allows for sufficient conditions to exist and allow the plant to stabilize within these conditions prior to performing the Surveillance. The normal outcome of the performance of a Surveillance is the successful completion which proves Operability. This change represents a relaxation over existing requirements. This change is consistent with NUREG-1433.

~ L9 Existing Surveillance Requirement 4.5.E.l.d requires verification that HPCI is capable of delivering at least 5000 gpm at normal reactor vessel operating pressure. The proposed surveillance, SR 3.5. 1.7, requires verification of a minimum 5000 gpm HPCI flow rate with reactor pressure e 920 psig and < 1010 psig. The HPCI performance test at high pressure is the second part of a two part test that verifies HPCI pump performance at the upper and lower end of the range of steam supply and pump discharge pressures in which the HPCI pump is expected to perform.

Performance of the HPCI test at both ends of the expected operating pressure range confirms that the HPCI pump and turbine are functioning in accordance with design specifications. The ability of the HPCI pump to perform at normal reactor vessel operating pressure has already been demonstrated. A small decrease in the pressure to as low as 920 psig at which the performance to design specifications is verified will not affect the validity of the test to determine that the pump and turbine are still operating at the design specifications.

BFN-UNITS 1, 2, tIL 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.1 - ECCS - OPERATING L10 Existing Surveillance Requirement 4.5.C. l.e requires verification that HPCI is capable of delivering at least 5000 gpm "at 150 psig reactor steam pressure." The proposed surveillance, SR 3.5. 1.9, requires verification of a minimum 5000 gpm HPCI flow rate with reactor pressure at a 165 psig. This change is less restrictive because it could allow reactor operation at pressures up to 165 psig prior to performing the surveillance. Performance of HPCI pump testing draws steam from the reactor and could affect reactor pressure significantly. Therefore, HPCI pump testing must be performed when the Electro-Hydraulic Control (EHC) System for the main turbine is available and capable of regulating reactor pressure. Operating experience has demonstrated that reactor pressures as high as 165 psig may be required before the EHC system is capable of maintaining stable pressure during the performance of the HPCI test.

The HPCI performance test at low pressure is the first part of a two part test that verifies HPCI pump performance at the upper and lower end of the range of steam supply and pump discharge pressures in which the HPCI pump is expected to perform. Performance of the HPCI test at both ends of the expected operating pressure range confirms that the HPCI pump and turbine are functioning In accordance with design specifications. The ability of the HPCI pump to perform at the lowest required pressure of 150 psig has already been demonstrated. A small increase in the pressure at which the performance to design specifications is verified will not significantly delay or affect the validity of the test to determine that the pump and turbine are still operating at the design specifications.

Ll1 CTS 3.5.E. 1 requires HPCI operability to be determined within 12 hours after reactor steam dome pressure reaches 150 psig from a COLD CONDITION. The proposed Note to SR 3.5.1.7 and 3.5. 1.8 allows X2 hours to perform the test after reactor steam dome pressure and flow are adequate. This is based on the need to reach conditions appropriate for testing. The existing allowance to reach a given pressure only partially addresses the issue. This pressure can be attained, and with little or no steam flow, conditions would not be adequate to perform the test - potentially resulting in an undesired reactor depressurization.

The proposed change recognizes the necessary conditions of steam flow and minimum pressure as well as a maximum pressure limitation and provides consistency of presentation of these conditions. The point in time during startup that testing would begin remains unchanged. The change simply changes when the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> clock for performing the test 10 Revision 0 PAGED() p~

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.1 >> ECCS - OPERATING must begin and permits testing to be completed in a reasonable period of time.

L12 Proposed Condition H provides direction for various interrelationships between HPCI and ADS, and Between LPCI and CS. The Action requires entry into LCO 3.0.3 for various combinations of inoperability which are consistent with the present required actions for the same various combinations (CTS 3.5.A.3, 3.5.B.4, 3.5.B.8, and 3.5.E.3). However, the time to reach MODE 4, Cold Shutdown (for LPCI and CS) and < 150 psig (for HPCI) has been extended from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> and to reach MODE 3, Hot Shutdown (for ADS only) has been extended from 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />. This provides the necessary time to shut down and cool down the plant in a controlled and orderly manner that is within the capabilities of the unit, assuming the minimum required equipment is OPERABLE. This extra time reduces the potential for a unit upset that could challenge safety systems. In addition, a new (more restrictive) requirement to be in MODE 2 in 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and MODE 3 (Hot Shutdown) within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> has been added (Reference Comment Ml above). These times are consistent with the BMR Standard Technical Specifications, NUREG 1433.

~ L13 An alternate verification to ensure the LPCI cross tie between loops is isolated has been added for Unit 3. The addition of an alternate method of satisfying the surveillance requirement is considered less restrictive. Currently, the method used for all three units is to verify the LPCI cross tie is closed and power is removed from the valve operator. Unit 3 has a manual shutoff valve install between the cross tie for Loop I and Loop II. This verification ensures that each LPCI subsystem remains independent and a failure of the flow path in one subsystem will not affect the flow path of the other subsystem. Since the manual shutoff valve serves the same function as the power operated valve, the proposed change is considered acceptable.

BFN-UNITS 1, 2, & 3 Revision 0 PAGE~(PP (P

S JUSTIFICATION FOR CHANGES BFN ISTS 3.5.1 - ECCS - OPERATING RELOCATED SPECIFICATIONS Rl Browns Ferry Nuclear Plant consists of three units. The pump suction and heat exchanger discharge lines of one loop of RHR in Unit 1 (Loop II) are cross-connected to the pump suction and heat exchanger of Unit

2. Unit 2 and 3 systems are cross-connected in a similar manner.

Technical Specification requirements related to RHR cross-tie capability between units have been deleted. The standby coolant supply connection and RHR crossties are provided to maintain long-term reactor core and primary containment cooling capability irrespective of primary containment integrity or operability of the RHR System associated with a given unit. They provide added long-term redundancy to the other ECC Systems and are designed to accommodate certain situations which, although unlikely to occur, could jeopardize the functioning of these systems. Neither the RHR cross-tie nor the standby coolant supply capability is assumed to function for mitigation of any transient or accident analyzed in the FSAR. Therefore, the operability requirements and surveillances associated with the cross-connection capability have been relocated to the Technical Requirements Manual (TRM). Changes to the TRM will be controlled in accordance with 10 CFR 50.59.

0 BFN-UNITS 1, 2, 5 3 12 Revision 0

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

,4 AUG 02 1989 3.5.A Co 4.5.A Co S a S st SS 4.5.A.l.d (Cont'd) 5'mS~C'~+on @c 105 psi Cho,+45 Q( Qpg ) 5+5 p dif'fcrential pressure betveen thc reactor vessel and the primary containment.

e. Check Valve Per Specification 1.0.MM

2. If onereactor loop CSS is inoperable, f. Verify that Once/Month the may remain in each valve operation for a period not to (manual, povcr-exceed 7 days providing operated, or all active components in automatic) in the the other CSS loop and the injection flovpath RHR system (LPCI mode) that is not locked, and the diesel generators scaled, or other-are OPERABLE. visc sccurcd in position, is in its correct+

position.

3~ If Specification 3.S.A.1 or 2. Ho additional surveillance Specification 3.5.A.2 cannot is required.

bc met, the reactor shall be placed in the COLD SHUTDOWH COHDITIOH vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4~ When thc reactor vessel pressure is atmospheric and Ql;caL: l.g irradiated fuel is in the eactor vessel at least one LCo core spray loop vith one Ze 5.g OPERABLE um associated Except that an automatic eccl generator shall be valve capable of automati PERABLE except vit the return to its ECCS positi reactor vcsscl head removed vhcn an ECCS signal is as specified in 3.5.A.5 r present may be in a TO STARTUP as position for another mode spccificd in 3.5.A.1. of operation.

Wc'ssFi(aH ~*a S~ 5<S4$ e(a~~ C~g~

4( BC'Sos l.S.J Clonic< BPH 15'f5 34a2.

BFH Unit 3 '/4 5-2 FAGE~oF 7 1 hMENDMENT NO. 16 9

4l 5fec;0;c)hoz r.s',z QEI: 15 f988 Al Mhen irradiated fuel is in the reactor vessel and the LCo zeac'tor vessel head is

~l cab'.Lsd removed, core spray is not required to be OPERhBLE provided the cavity is flooded, the fuel pool 'Its PssW SR 3 S'.

gates are open and the fuel pool vater level is maintained above the lov level alarm point and rov one V ump ass ciate valv su ply thc andb coo ant s ply are OPERhBLE Pisl'sos> ~IF Z. 5.z. S'r Profosc'L /tCT'I oW5 GSS Mhcn vork is in progress vhich has the potent al to drai the vessel, ual nitia on apabilit of ei er 1 SS L p or 1 pum vith he ca bility o injec ng va into he re cl assoc ate ese generator(s) are required.

Me SusHk~m~on 0 r C~C 4o s~ >mrs z,~.~

BFK 3.5/4.5-3 AMENDMENT 10. y6g Unit 1

kl

8. If Specifications 3.5.B.1 8. No additional surveillance through 3.5.B.7 are not met, required.

orderly shutdown shall

~

an initiated and the reactor shall be placed in the COLD SHUTDOWN CONDITION be

<r< rus+Amaon W B<H t S'TS 'R.s.l P r r h ~

ithin 24 hours.

~R

9. When the reactor vessel 9. When the reactor vessel APQ'cab Jig pressure is atmospheric and pressure is atmospheric, irradiated fuel is in the the RHR pumps eactor vessel, at least one that are required to e Mo RHR loop with two pumps or two OPERABLE shall be Z.

3. 5o2. loops with one pump per loo demonstrated to be OPERABLE shall be OPERABLE. c pumps per Specification 1.0.MN.

soc ate mesc generators ust also be OPERABLE.

prcssure coo an xngcction St'~ 3uSA/'cocoon Pg,r Cha~t Nag (LPCI) may be considered Ac BPN ISIS g.g.a For OPERABLE during alignment SR xs;zA and operation for shutdown cooling, if capable of being manually realigned and not otherwise inoperable.

LCu If thc conditions of nce Specification 3.5.A.5 are met, Hept:ab;l+ LPCI and containment cooling arc not re uired.

When there is irradiated fuel 11. The RHR pumps on the in the reactor and thc reactor adjacent units which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall be. demonstrated to be associated heat exchangers and OPERABLE per Specification valves on an adjacent unit 1.0.MN when the cross-must be OPERABLE and capable connect capability of supplying cross-connect is re uired capability except as specified in Specification 3.5.B.12 below. (Note: Because cross- pre S~6C:~o ger Cha~S connect capability is not a 4 isTs z.s.(

short-term requirement, a BAN component is not considered inoperable if cross-connect capability can be restored to service within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.)

BFN 3.5/4.5-7 'ANENOMENT NO. 2P4 Unit 1 PAGE OF

4

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C~g5 hsc B~ sFecl+;cg,go& 7 s I 3,ge <<(+2 R

LIMITIHG COHDITIOHS FOR OPERATIOH VEILLAHCE REQUIREMEHTS 3.7 4.7 cab Applies to the operating status Applies to thc primary and of the primary and secondary secondary containment containmcnt systems. integrity.

OOQ~LvV To assure the integrity of the To verify the integrity of the primary and secondary primary and secondary containment systems. containment.

A. C a At any time that thc irradiated fuel is in th reactor vessel, an the S'C Z,S,2> I nuc car s em s pressurized ai Thc suppression ov tmos hcric ressure chamber vater level S< 3.S.~. or work is being done v be checked once cr has the potential to drain enever heat the vessel, thc pressure s added to the su 1 vatcr level suppression pool by Ag ~t;~ d tern eratur s a e testing of thc ECCS 4 Leo@, g,g maintained vithin the or relief valves the folloving limits. pool temperature shall be continually monitored and shall

'be observed and

a. Minimum water level ~ logged every

-6.25" (differential 5 minutes until the pressure control >0 paid) heat addition is

-7.25" (0 paid differen- terminated.

tial pressure control) b Maximum vater level ~

~ 1N BFH 3.7/4.7-1 Unit 1 PAGE

i

3. .C. S utdo 4.9 ~ G~ 0 S do Whenever the reactor is'n l. Ho additional COLD SHUTDOWH COHDITIOH vith surveillance is irradiated fuel in the required.

reactor, the availability of electric power shall be as specified in Section.3.9.A except as specified herein. See AsÃkcah~~ N CQ yy 8~< lS'75 Sec+io~ 7,f

l. At least tvo units 1 and 2 diesel generators and their associated 4-kV shutdown boards shall be OPERABLE.

2. An additional source of pover energized and capable of supplying power to the units 1 and 2 shutdovn boards consisting of at least one of the following:

a. One of the offsite pover sources specified in 3.9.A.1.c.

b. A third OPERABLE diesel generator.

3. At least one 480-V shutdown board for each unit must be OPERABLE.

4. One 480-V RMOV boar mg t is uire for ach boar (1D o 1E) ired t suppo t oper tion o the syst in ac ordanc vit 3.5.B.

3.9/4.9-15 AMENDMENT tttO, 203 BFH Unit 1  ;-"..~~r'F

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP PAGE~OF~

Cr.X'C. 4;o 3. K.Q AUG OR 1998 3 5.h 4 ~ 5.h S SS 4-5-h l.d (Cont'd) 105 psi Scc. awc$ ;P,~g,.

differential pressure 8 ~~ +~ Sr's~ 8 s/ betveen the reactor vessel and the primary containment.

e. Check Valve Per Specification 1.0.MM

2. If one CSS loop is inoperable, f. Verify that Once/Month the reactor may remain in each valve operation for a period not to (manual, pover-exceed 7 days providing operated, or all active components in automatic) in the the other CSS loop and the ~ection flovpath RHR system (LPCI mode) that is not locked, and the diesel generators sealed'r other-are OPERhBLE. vise secured in position, is in its correct+

position.

30 If Specification 3.5.h.l or 2. Ho additional surveillance Specification 3.5.1.2 cannot is required.

be met, the reactor shall be placed in the COLD SHUTDOWN COHDITIO hours.

When the reactor vessel ressure is atmospheric and irradiated fuel is in the eactor vessel at least one core spray loop vith one OPERABLE pump assoc ated Except that an automatic esel generator shall be valve capable of automatic PERhBLE except vith the return to its ECCS position" reactor vessel head removed vhen an ECCS signal is as s ecified in 3.5.h.5 r present may be in a PRIOR TO as position for another mode specified in 3.5.h.l. of operation.

'st t 3 sagk i(icd i ~ 4~ ~cc ZNsJAi~,f'>a~ g~ Ck~ggf c C~grg W Bf~ 1sT< 3 > I +~ ~FIJ Isis z.g.2 BPH 3.5/4 '-2 Unit 2 hMENWENNO. 16 9

8 5

~Pter fi~fio~ 3. 5. ~

DEC 15 l988 When irradiated fuel is in the reactor vessel and the Lco 3.S Z.

reactor vessel head is removed, core spray is not required to be OPERABLE provided the cavity is flooded, the fuel pool P~opocM Sg 8.<.B.A-gates are open and the fuel pool vater level is maintained above the lov level alarm point and r v e one W puhy and ssociated alves g suppl the st dby coolant supply are 'Popo~ S~ 8.S:2.~

OPERABLE. CSS p<<posW ACnoaS .

• When vork is in progress vhich ha the potenti l to drai the vess l, manual i tiation capab ity of eith l CSS Loop or RHR pump, ith the capabili of injecti te 411 the assoc ate ese enerator(s) are re uired s,~ z~~$ ;4Lc 4'~ 4r 0 3.F.2-

~ ~

~

BFH 3.5/4.5-3 AMENDMENT g6. ~g8 Unit 2 PAGE~i-iF~

S ent 'nmen t

8. If Specifications 3.5.B.1 8. No additional surveillance through 3.5.B.7 are not met, required.

an orderly shutdown shall be initiated and the reactor >< ~~s4i4c f~ 4, C~rri.

shall be placed in the 4r Bf'N I s~g COLD SHUTDOWN CONDITION within 24 hour

9. en the reactor vessel 9. When the reactor vessel pressure is atmospheric and pressure is atmospheric 4t't~W J.k> irradiated fuel is in the reactor vessel, at least one that are required to be LCo RHR loop with two pumps or two OPERABLE shall be 3.5.Q loops with one pump per loop demonstrated to be OPERABLE shall be OPERABLE. e pumps per Specification 1.0.HM.

associated diesel generators must also RABLE Low pressure coolant injection (LPCI) may be, considered OPERABLE during alignment and operation for shutdown cooling, if capable of being manually realigned and not otherwise inoperable.

CQ O~ t e conditions o

~pl;~'.);t ~ Specification 3.5.A.5 are met, 404pk4%84 ~

LPCI and containment cooling re not re When t ere is irradiated fuel The RHR pumps on the in the reactor and the reactor adjacent units which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall be demonstrated to be associated heat exchangers and OPERABLE per Specification valves on an adjacent unit 1.0.MM when the cross-must be OPERABLE and capable connect capability of supplying cross-connect is required.

capability except hours' as specified in Specification 3.5.B.12 below. (Note: Because cross- Sec.QNgf<f<~$ ~ Qi connect capability is not a

( ~~~

~4 g~> <sees B,g short-term requirement, a (

component is not considered inoperable if cross-connect capability can be restored to service within 5 )

BFN 3. 5/4. 5-7 AMENDMENTRD. 223 Unit 2

~pc< Fice y i'o~ Z. g ~

AUG 02 1989 IREMEHTS Whenever thc core spray systems, The folloving surveillance LPCI, HPCI, or RCIC are requi.red requirements shall be adhered to be OPEBhBLE, the discharge to assure that thc discharge piping from the pump discharge 'iping of the"core spray of these systems to thc last systems, LPCI , an RCI block valve'hall be filled. are filled.

Thc suction of thc RCIC and HPCI 1. Every month an pr or toi e pumps shall be aligned to the t t ng o the S (LPCI and condensate storage tank, and Cont ent Spray) and co the pressure suppression chamber spra system the discharge head tank shall normally bc aligned p ping of these systems s a to serve the discharge piping of 3 e ~te flo~etermi and visitor re e ed pqint the RHR and CS pumps. The condensatc head tank may be used to scrvc thc RHR and CS discharge 2~ Folloving any per o v ere piping if the PSC head tank is unavailable. The prcssure e,LPCI or co e spray systems ha e not been r ired ~ be

'ndicators on the discharge of the OPE, the dis rge ping of th inoperable system shall RHR and CS pumps shall indicate not less than listed belov. be vent+ from the high point prior to the return of thc Pl-75-20 48 psig system to Pl-75-48 48 psig Pl-74-51 48 psig 3. Whenever the HPCI or RCIC Pl-74>>65 48 psig system is lined up to take suction from the condensate storage tank, the discharge piping, of thc HPCI and RCIC shall be vented from the high point of the system and vater flov observed on a monthly basis.

Sec a4c44i~)o Q, PL

4. en the RHRS e SS are 85~ Isrs 35/~353 QCt'r rc ired to e OPE LE, he pres re indi ators ich

~p,) monito the di charge nes shall be onitored daily and the prcssure recorded.

BFH 3.5/4.5-17 AMStNENT Rt3. I6 g Unit 2 PAGE

sec wgfgq,s:~ P 5 ficRli~ 3.5,Q C4o~y gr gru I JMX S.g.2./ f-~

ceo LIMZTIHG COHDITIOKS FOR OPE1RTI05 SURVEILLhHCE REQUIREMENTS

~ 7 4~7 C Applies to the operating status Applies to the primary and of the primary and secondary secondary containment containment systems. integrity.

~O~JJv Qhiaafze To assure thc integrity of thc To verify the integrity of the primary and secondary primary and secondary containment systems. containment.

1. At amr time that the irradiated fuel is in the SR reactor vessel and the as.z I nuclear system is pressurized a. The suppZession above atmospheric prcssure chamber water level or wor s e done whi b checked once er has the potential to drain enever heat the vessel,'Ke prcssure is added to the suppression ool wats lcvc suppression pool by temperature testing of the ECCS ma nta ed within the or relief valves the following limits. pool temperature shall be continually monitored and shall bc observed and logged

a. Minianun water level ~ every 5 minutes

-6.25" (differential until the heat pressure control >0 paid', addition is

-7.25" (0 psid differen- terminated.

tial prcssure control.

b. Maximum water level ~

BFH 3.7/4.7-1 OF V Unit 2

+ CcifiC%4iue Z.S. Q VAN 0 8 $ 99$

3.9.C. 0 o C d udo 4.AC 0 Co d S utdo whenever the reactor is in ~~ ao aoclltlonsl COLD SHUTDOWN COHDITIOH vith surveillance is irradiated fuel in the required.

reactor, the availability of electric pover shall be as specified in Section 3.9.A except as specified herein.

l. At least tvo Units 1 and 2 diesel generators and their associated 4-kV shutdown Sea 3453 fscR'4d~ Vol C lg-Jp!

boards shall be OPERABLE.

B~+ I~~ Seel~~

2. An additional source of 9.f'.

pover energized and capable of supplying pover to the Units 1 and 2 shutdovn boards consisting of at least one of the folloving:

One of the offsite pover sources spec'fied in 3.9.A.l.c.

b. A third OPERABLE diesel generator

3. At least one 480-V shutdown board for each unit must be OPERABLE.

4. One 480-V RMOV board set required or each OV bo d (2D or require to supp t operatio of the RHR system accordance vith 3.5.B.9.

ANENOMENT RO. 186 BFH 3.9/4.9-15 Unit 2 PAGE~OF~

4 UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

deci gi earn AUB 02 lggg At 4.5.k 4.5.k.l.d (Cont'd) 105 psi differential GV&hkiWA on Ar pressure between the C~(y g @g /pe g5yg reactor vessel 3.5.i and the yrimary contaimaent ~

e. Testable Per Check Valve Specification Z.O.M

2. If one CSS loop is inoperable, f. Verify that Onc thc reactor may remain in each valve operatian for a period not to (manual y paver exceed 7 days providing oyerated, or all active components in automatic) in the thc other CSS loop and the infection flowpath RHR system (LPCI mode) that is not locked, and the dicscl generators sealed, or othcr-are OPERkSLE. vise secured in positiang is in its correct+

position.

3. If Specification 3.5.h.l or 2. No additional surveillance Syecificatian 3.5.k.2 cannot is re~ired.

be met, the reactor shall be placed in the COLD SHOTDOWÃ COHDITIOE vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4. When the reactor vessel yressure is atmospheric and irradiated fuel is in the reactor vessel at least one

( core syray laop vith one Z.S ~ CO umy associate Except that an automatic esel generator shall b valve capable of automatic OPERABIZ exccyt vith the return to its ECCS position reactor vessel head rcmovcd when an ECCS signal is as s ecificd in 3 AS.A.5 r present may bc in a RIOR as position for another mode s ecificd in 3.5.k.l. of apcration.

5i-< ~u&llca,giin Qp I~~ A~ xs 55 3.5; I See Z~sk:t';i,g~ 4 g~V Isis g.~.<

CIi-)~

BFH 3.5/4 '-2 PAGE~OF~

Unit 3 NENONKNTNO. 1 O 0

Cl, Sfec.>gcW~ 3. 5.2; DEC 15 1988

• s. When irradiated fuel is in thc reactor vessel and the LGo gg.2 reactor vessel head ia removed, core spray is not 4'l'mb: lifp required to be OPERABLE provided thc cavity is flooded, thc fuel pool Pw os' gates are open and the fuel pool vater level is maintained above the lov evel alarm point ro ne p assoc atcd val cs s plying e stan y coo ant sup y are ~s Sg, 3.g.g,g OPE LE

~ cs~

~oSect AC7 gong

• When vork is in p gress vhich as thc po ential drain the ssel, man al init tion c ability o either CSS Loo or 1 pump, vi h the capa ility of a/ecting va cr into he reacto vessel c e generator(s) are required.

Se< 3'~f;~go~ Q~ gA BFH 3.5/4.5-3 AMENOMENT N5. gP2 Unit 3

Cl

8. If Specifications 3.5.B.1 8. No additional surveillance through 3.5.B.7 are not met, required.

an orderly shutdown shall be initiated and the reactor Sc< 5<sWVi ca,Ao n shall be placed in the &< add tsrs ~.s.

COLD SHUTDOWN CONDITION ~

within 24 hours.

SR Z.5,2,S the reactor vessel

9. When the reactor vessel When pressure is atmospheric and pressure is atmospheric, irradiated fuel is in the the RHR pumps reactor vessel, at least one that are required to e LCn RHR loop with two pumps or two OPERABLE shall be 3.

loops with one pump per loop demonstrated to be hall be OPERABLE. e pump OPERABLE per assoc@a e xesel gener or Specification 1.0.MM.

must also be OPERABLE Low pressure coolant njection ~c 3'u5~'eaHo~ g I C4~

(LPCI) may be considered b~e 1STS r,8.z OPERABLE during alignment sR iand operation for shutdown X5 2,g cooling, if capable of being manually realigned and not otherwise inoperable.

~o 10 If the conditions of Specification 3.5.A.5 are met, A(piiu b:[Q LPCI and containment cooling

~Le not required.

en there is irradiated fuel 11. The and D RHR pumps on in the reactor and the reactor 'nit B 2 which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall be demonstrated to associated heat exchangers and be OPERABLE per valves on an adjacent unit Specification 1.0.MM when, must be OPERABLE and capable the cross-connect of supplying cross-connect capability is required. e'FN capability except as specified in Specification 3.5.B.12 below. (Note: Becaus~ cross-connect capability is not a short-term requirement, a e< gu~'Fi'WHon

&4 /PE 15 'f5 4r ~p component is not considered inoperable if cross-connect capability can be restored to service within 5 hours.)

AMENDMENT No. X 77 3.5/4.5-7 Unit 3

'c NN 1 S 1994 5g X Whenever the core spray systems, e fol owing surveillance LPCI, HPCI, or RCIC are required requirements shall be adhered to be OPERABLE, the discharge to assure that the discharge piping from the pump discharge piping of the core s ray of these systems to the last systems, LPCI, HPCI, an CIC block valve shall be filled- are fille The suction of the RCIC and HPCI Eve month and prio to t pumps shall be aligned to the esting o the RS (L I and condensate storage tank, and Con ament Spra and c re the pressure suppression chamber s ray s ems the dischar e head tank shall normally be piping of these systems shal aligned to serve the discharge e v e rom e xgh po t piping of the RHR and CS pumps. and wa flow dete~ned.

The condensate head tank may be used to serve the RHR and CS 2. o owing any period where the discharge piping if the PSC head tank is unavailable. The LPCI or core spray syst ve not been req red to pressure indicators on the discharge of the RHR and CS pumps 2 OP LE the disch g e P P x g of th noperable sys i

shall shall indicate not less than be vente rom the high oint listed below. prior to the turn of the system to;service.

Pl-75-20 48 psig Pl-75-48 48 psig 3. Whenever the HPCI or RCIC Pl-74-51 48 psig system is lined up to take PI-74-65 48 psig suction from the condensate

'torage tank, the discharge piping of the HPCI and RCIC shall be vented from the high point of the system and water flow observed on a monthly basis."

4. en the RS and he CSS are r uired to be OP BLE, the pre ure in cators ich moni o the d charge ines shall e onito ed dai and the pr sure rec rded.

BPÃ 3.5/4.5-17 NENDMHfT i(0. 1 78 Unit 3 PAGE 5 QF~

Skc>g~

LDGTZBC CONDITIO?N ZOR OPERLTIOS SURVEILLAECE REQUIREHEHTS 3.7 4.7 kppliea to the operating'status hypliea to the primary and of the priaary and secondary secondary contahunent containNent ayateaa. integrity.

To assure the integrity of the To veri~ the integrity of the priaary and secondary priaLary and secondary contahaent ayateaa. cont ainccnt ~

l. Lt any togae that the GAS.S.z.

irradiated fuel ia in the 1 reactor vessel, e xmc e s ea yressurixed a. The auyyreaaion shore ataoapheric yreaaure chaaber water level or r

~the the vessel, e one yotential to drain the pressure glv$

be checked once per enerer heat a added to the gdd suppression pool water level suppression pool by walib& tcRpera testing, of the ECCS

~ 35'~ aa ta within the or relief valves the

'following liaita. yool temperature shall be conthmally acmitored and shall be obaerred and logged

a. Madam water lerel ~ every 5 minutes

-6.25" (differential until the heat pressure control >0 yaid) addition is

-7.25" (0 ysid differen- terainated.

tial yreaaure control)

. Maxima water level a See Q~g f 'Non Q Chang)~

~~ '~<> 34"Z.t +a BF5 3.7/4.7-1 PAGE~OF~

Unit 3

Cl 3.9.C. 0 S 0 4.9.C 0 0 S DOWN

~CO DIXIE ~CO )~~0 Whenever the reactor is in the 1. Ho additional COLD SHUTDOWH COHDITIOH vith surveillance is irradiated fuel in the required.

reactor,. the availability of electric pover shall be as specified in Section 3.9.A except as specified herein. sc'c'5% f.'ca5~n far

+~ ><<JSVS 5 Ao q,~

c~~

l. At least tvo Unit 3 diesel generators and their associated 4-kV shutdovn boards shall be OPERABLE.

2. An additional source of pover energized and capable of supplying pover to the Unit 3 shutdown boards consisting of at least one of the folloving:

a. One of the offsite pover sources specified in 3.9.A.l.c.

b. A third OPERABLE diesel generator.

3. At least one Unit 3 480-V shutdown board must be OPERABLE.

4. One 480- RNOV b ard motor nerator (mg) se is re uired fo each OV board (3D r 3E) r uired o suppo t operat on of e RHR system n accor nce v h 3.5.B.9 ~

AMENDMEQ S~g

~z ~

BFH 3.9/4.9-14 8 VIs.

Unit 3

13USTIFICATION FOR CHANGES BFN ISTS 3.5.2 - ECCS - SHUTDOWN ADMINISTRATIVE CHANGES A1'eformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

Surveillance Requirements for MOV operability that are required by the Inservice Testing (IST) Program have been removed from individual Specifications. This change is considered administrative in nature since these requirements remain in the IST Program which is defined by proposed Specification 5.5.6.

A3 CTS 3.9.C.4 requires one 480 V reactor motor operated valve (RMOV) board motor-generator (MG) set for each RMOV board required to support the RHR System in accordance with CTS 3.5.B.9. The 480-V AC RMOV boards provide motive power to valves associated with the LPCI mode of the RHR system.

The MG sets act as electrical isolators to prevent a fault propagating between electrical divisions due to an automatic transfer. The inability to provide power to the inboard injection valve and the recirculation pump discharge valve from either 4 kV board associated with an inoperable MG set would result in declaring the associated LPCI subsystems inoperable and entering the Actions required for LPCI.

Therefore, the deletion of the operability requirement associated with the MG sets in CTS 3.9.C.4 is considered administrative.

BFN-UNITS 1, 2, 5 3 Revision 0 PAGE /

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.2 - ECCS - SHUTDOWN TECHNICAL CHANGE - MORE RESTRICTIVE Ml Proposed ACTIONS A, B, C and 0 have been added to provide required actions be taken when LCO requirements can not be met. CTS 3.5.A.4 and 3.5.B.9 provide minimum requirements for ECCS subsystems when in MODE 4 and 5 (except with the spent fuel pool gates. removed and water level a the low level alarm setpoint of the spent fuel pool) but no action if these requirements are not met. Therefore, technical specifications are violated when these requirements can not be met and the default to TS 1.0.C. 1 requires no action since the plant is already in Cold Shutdown.

While from a compliance standpoint the proposed ACTIONS are less restrictive, from an operational perspective they are more restrictive since actions are required w'here there were none before. Proposed ACTION A allows 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to restore a subsystem when only one of the required subsystems is inoperable and then proposed ACTION B requires action be initiated to suspend operations with a potential for draining the reactor vessel (OPDRVs) immediately. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time is considered acceptable based on engineering judgment that considers the remaining available subsystem and the low probability of a vessel draindown event during this period. With no required ECCS injection spray subsystems inoperable, proposed ACTION C requires action to be initiated immediately to suspend OPDRVs and at least one required subsystem be restored to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. If one subsystem can not be restored within four hours then Proposed ACTION D requires action be initiated immediately to restore secondary containment to OPERABLE status, to restore two standby gas treatment systems to OPERABLE status, and to restore isolation capability in each required secondary containment penetration flow path not isolated.

These actions must be immediately initiated to minimize the probability of a vessel draindown and the subsequent potential for fission product release.

M2 Proposed SR 3.5.2. 1 has been added. SR 3.5.2. 1 requires the suppression pool water be verified ~ a minimum level every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. CTS 3.7.A.1 (8 4.7.A. l.a) requires the suppression pool be verified e -6.25" with no differential pressure control once per day at any time irradiated fuel is in the reactor vessel, and the nuclear system is pressurized or work is being done which has the potential to drain the vessel. Therefore, proposed SR 3.5.2.1 is more restrictive since the frequency of performance has been increased from once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In addition, CTS only requires performance during atmospheric conditions when work is being done that has the potential to drain the it 0 vessel. Therefore, the proposed SR is more restrictive since BFN-UNITS 1, 2, 5 3 Revision 0 PAULO';" 6

Cl JUSTIFICATION FOR CHANGES BFN ISTS 3.5.2 - ECCS - SHUTDOWN requires performance during MODES 4, and 5, except with the spent fuel storage pool gates removed and water greater than or equal to minimum level over the top of the reactor pressure vessel flange. The CTS requirement to check the maximum level during OPDRVs has not been included since Specification 3.5.2 concerns the ability to maintain reactor water level using the suppression pool as a source of water.

However, this level check is required for proposed Specifications 3.6.2.1 and 3.6.2.2 as it relates to Containment Systems.

M3 Proposed SR 3.5.2.4, which requires a verification every 31 days that ECCS injection/spray valves are in their correct position, has been added. This provides assurance that the proper flow paths will exist for ECCS operation. This is more restrictive since BFN currently only requires this check during MODES 1, 2 and 3.

M4 An SR has been added to require a system flow rate test for the Core Spray System during atmospheric conditions. While CTS (4.5.B.9) requires flow rate testing of the RHR pumps during atmospheric conditions as well as during MODES 1, 2, and 3, it only requires CSS flow rate testing during MODES 1, 2, and 3. The addition of this requirement is more restrictive.

TECHNICAL CHANGE - LESS RESTRICTIVE "Generic" LA1 CTS 4.5.H. 1 requires the discharge p'iping of RHR (LPCI and Containment Spray) to be vented from the high point and water level determined every month and prior to testing of these systems. The specific requirement to vent prior to testing has been relocated to procedures. Changes to the procedures will be controlled by the licensee controlled programs.

LA2 Any time the OPERABILITY of a system or component has been affected by repair, maintenance or replacement of a component, post maintenance testing is required to demonstrate OPERABILITY of the system or component. Therefore, explicit post maintenance Surveillance Requirements have been deleted from the Specifications. Also, proposed SR 3.0.1 and SR 3.0.4 require Surveillances to be current prior to declaring components operable.

PAGE~OF BFN-UNITS 1, 2, & 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.2 - ECCS - SHUTDOWN LA3 Details of the methods of performing surveillance test requirements and routine system status monitoring have been relocated to the Bases and procedures. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in proposed BFN ISTS Section 5.0 and changes to the procedures will be controlled by the licensee controlled programs.

"Specific" Ll CTS 3.5.A.5 requires manual initiation capability of either 1 CSS Loop or 1 RHR pump with capability of injecting water into the reactor vessel when work is in progress which has the potential to drain the vessel.

The proposed Specification would not require the CSS or RHR (LPCI and containment cooling mode) system to be operable since LCO 3.5.2 applicability does not apply when the fuel pool gates are open and the fuel pool water level is maintained above the low level alarm setpoint.

Therefore, the deletion of this requirement is considered less restrictive. The deletion is acceptable since the coolant inventory represented by this water level is sufficient to allow operator action to terminate the inventory loss prior to fuel uncovery in case of an inadvertent draindown.

L2 The proposed LCO for ECCS-Shutdown is less restrictive since it only requires two low pressure ECCS subsystems to be OPERABLE. This can be fulfilled with any combination of RHR and CS subsystems. That is, two CS subsystems (a CS subsystem for Specification 3.5.2 consists of at least one pump in one loop), two RHR subsystems (RHR subsystem for Specification 3.5.2 consists of one pump in one loop), or one RHR subsystem and one CS subsystem OPERABLE. CTS 3.5.B.9 requires one RHR loop with two pumps or two RHR loops with one pumps per loop to be .

OPERABLE. CTS 3.5.B.4 requires one CS loop with one pump per loop to be OPERABLE. Per CTS 3.5.A Bases the minimum requirement at atmospheric pressure is for one supply of makeup water to the core. Therefore, requiring two RHR pumps and one CS pump to be OPERABLE provides excess redundancy. In addition, since only one supply of makeup water is required, sufficient makeup water can be provided by two CS subsystems, two RHR subsystems, or one CS and one RHR subsystem. As such, the proposed Specification ensures redundancy by requiring any two low pressure ECCS subsystems to be OPERABLE.

BFN-UNITS 1, 2, & 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.2 - ECCS - SHUTDOWN RELOCATED SPECI F I CAT IONS Rl Browns Ferry Nuclear Plant consists of three units. The pump suction and heat exchanger discharge lines of one loop of RHR in Unit I (Loop II) are cross-connected to the pump suction and heat exchanger of Unit

2. Unit 2 and 3 systems are cross-connected in a similar mariner.

Technical Specification requirements related to RHR cross-tie capability between units have been deleted. The standby coolant supply connection and RHR crossties are provided to maintain long-term 'reactor core and primary containment cooling capability irrespective of primary containment integrity or operability of the RHR System associated with a given unit. They provide added long-term redundancy to the other ECC Systems and are designed to accommodate certain situations which, although unlikely to occur, could jeopardize the functioning of these systems. Neither the RHR cross-tie nor the standby coolant supply capability is assumed to function for mitigation of any transient or accident analyzed in the FSAR. Therefore, the operability requirements and surveillances associated with the cross-connection capability have been relocated to the Technical Requirements Manual (TRM). Relocation to the TRM is in accordance with the "Application of Selection Criteria to BFN TS" and the NRC Final Policy Statement on Technical Specification Improvements. Refer to the application document discussion for additional information.

BFN-UNITS I, 2, & 3 Revision 0

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP PAGE OF

SfCC< CiCOQO m 3 i5 i3 FEB 0 7 199$

3.5.E es ure Coo a t ectio 4.5.E essu e Coo a t ect o S st C S S ste HPC S 4.5.E.1 (Cont'd)

e. Flow Rate at Once/18 Sce'uste C>>capon go>>

150 psig months ages Q>> gFv4 l5TS 3,5,( The HPCI pump shall deliver at least 5000 gpm during each flow rate test.

f. Verify that Once/Month each valve (manual, power-operated, or automatic) in the injection flow-path that is not locked, sealed, or otherwise secured in position, is in its correct* position.

2. If the HPCI system is 2. No additional surveillances inoperable, the reactor may are required.

remain in operation for a period not to exceed 7 days, provided the ADS, CSS, RHRS (LPCI), and RCICS are OPERABLE.

3. If Specifications 3.5.E.l

• Except that an automatic or 3.5.E.2 are not met, valve capable of an orderly shutdown shall automatic return to its be initiated and the ECCS position when an reactor vessel pressure ECCS signal is present shall be reduced to 150 may be in a position for psig or less within 24 another mode of hours. operation.

eactor Co LCO 1. The RCICS shall be OPERABLE RCIC Subsystem testing "hall P.S,> whenever there is irradiated be performed as follows:

fuel in the reactor vessel pc~i b C J and the reactor vessel 5'g3,5g,g a. Simulated Auto- Once/18 pressure is above 150 psig, A'3 matic Actuati'on .-..oaths except in the COLD SHUTDOWN P~ppQ Vcr Test CONDITION or as specified in sR 3.5.3~

3.5.F.2. OPERABILITY shall BFN 3.5/4.5- 14 AMENDMENT Ho. g8 O Unit 1 =;:r'~P QF

5 ci+icgQoq Z 5'.3 NOV 24 1989 e determined vithin 12 hours SP3.5.3.3 b. Pump Per (oped after reactor steam pressure OPERABILITY Specifi-reaches 150 psig from a COLD cation

"~~~~ COHDITIOH em veiny 1.0.MM PQOQ T ST TU by ing Ran a~lory ste pl c. M Va tor-0 era e

d er eci PE BILI cat on 1.0.MM 9z ~~T>

S R3. S,p,p d. Flov Rate at Once/N PAyc se4 blue. rma re ctor s Ai sRRs;p, ve sel pe ating pre ure Olo P SRP.S >.q e. Flov Rate at Once/18 psig months

~ ILS Se 3. S,q,p The RCIC pump shall SR g.g,p g deliver at least 600 gpm during each flov test.

rlkqs 2 ~ If the RCICS is inoperable, SR Z.S.'3. 2 f. Verify that Once the reactor may remain in each valve Qc7 le operation for a period not (manual, pover-A to exceed W days if the operated, or automatic) in the IQ HPCIS s OPERABLE during La such time ~ ygi.,Q in)ection flovpath that is not locked, 3 ~ If Specifications .5.F.1 Be~

Aodc 3 in sealed, or other-vise secured in or 3.5.F.2 are not met, an IWhts position, is in its

~~~k. and the reactor be depressurized to correc osition.

A4, shall less than 150 psig within 24'ours.

ore~~ ~ Except that an automatic valve capable of automatic return to its normal position when a signal is present may be in a position for another mod of o eration.

BFH Unit 1 3.5/4.5-15 AMENOMENT NO. I7 3 PAGE

8

>f'eciWi an 3,5,3 m 19 1994 Hm.

5'g 8'.C.3. J

-Whee>~ he core s ra s stems The following surveillance HPCI or ZC .ar required requiremeats shall be adhered to OPERAB , t dis arge to assure that the discharge pipin from the pum disc rge piping of the ore spray the systems to e la t gg( yetems, , HPCI, an RCIC b ck va ve shall be f lie a x ed:

The ctioa of the RCIC d HPC Every month and prior to the pumps 11 aligned to the testing of the RHRS (LPCI and condeasa storage tank, d Containment Spray) and core e pressure on chambe spray system, the discharge head tank shall normally be piping of these systems shall aligned to serve the discharge be vented from the high point piping of the RHR aad CS pumps. aad water flow determined.

The condensate head tank may be used to serve the RHR and CS Following any period where the discharge piping if the PSC hea LPCI or core spray systems tank is unavailable. The have not been required to be pressure indicators on the OPERABLE, the discharge piping discharge of the RHR and CS of the inoperable system shall pumps shall indicate not less be vented from the high point than listed below. prior to the return of the system to serv Pl-75-20 48 psig 5 R 3.$.3. )

Pl-75-48 48 psig 3. Whenev RCIC Pl-74-51 48 peig system is lined up to take 1-?4-65 48 psig suction from the condensate stora e tank, the discharge iingof te RCIC s 1 e ven ed f m tge gh po t o the a'n at flo obs e cm s monthly as s.

Sr+ Ycc+Q~,g

~~< 1ST5 3.g.) 4.,When the RHRS and the CSS are required to be OPERABLE, the pressure indicators which monitor the discharge lines shall be monitored daily and the pressure recorded.

BFN 3. 5/4. 5-17 NENOMENT NO, 2 06 Unit 1 PAGE~GP

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP

~ w *~

>

~PC/i gi ~%ion 3 ~ 3 (g FEB 0 7 1991

.5.E s Co a t ct o 4.5.E ssu Co t 'ect o S ste C S S stem C S 4.5.E.1 (Cont'd)

e. Flov Rate at Once/18 150 psig months The HPCI pump hhall deliver at least 5000 gpm during CL Dv$ 4limftow d'or each flow rate test.

<ha-P~s 4'o~ BPhl ISIS g,s.i f. Verify that Once/Month each valve (manual, pover-operated, or automatic) in thc injection flov-path that is not locked, sealed, or othervise secured in position, is in its correct+ position.

2. If the HPCI system is 2. No additional surveillances inoperable, the reactor are required.

may remain in operation for a period not to exceed 7 days, provided the ADS, CSSo RHRS(LPCI), and RCICS arc OPERABLE.

3. If Specifications 3.5.E.l

• Except that an automatic or 3.5.E.2 are not met, valve capable of automatic an orderly shutdovn shall return to its ECCS position be initiated and the vhen an ECCS signal is reactor vcsscl pressure present may be in a shall be reduced to 150 position for another mode psig or less vithin 24 of operati l C< 1. Thc RCICS shall be OPERABLE 1. RCIC Subsystem testing shall vhenever there is irradiated be performed as follovs:

fuel in the reactor vessel Pc or LI and the reactor vessel 5'R3.5.3.5 a. mulated Auto- Once/18

~ppi'c4.i ~~ prcssure is above 150 psig, matic Actuation months except in the COLD SHUTDOWN Test CONDITION or as specified in P.,~~ Noh 3.5.F.2. OPERABILITY shall r sa >5.>>

BFN 3.5/4.5-14 NENOMENr No. 190 Unit 2 >~sM PAGE N OF ie 3.s3.9

S CRJXiCOJAJOM NOV 24 1999 4.5.F.1 (Cont d) be determined vithin 12 hour SR'3.5.5.3 b. Pump Prop@~

M4e ~ after reactor steam pressure OPERABILITY Specifi-sg g.s.g f reaches 150 psig from a COLD CONDITION or a ernat ve y cation 1.0.MM RIOR~0 RRRR~Oy naROR an auxilia~ steam tor-Operat d Per supply.'A3 Va e Spec+i-OPE LITT ation~

1. O.MM 2JRRO S s~ s.s.3.5 d. Flov Rate t Once HJf Ol+O ~4 orma react r 4 sR 8.5.3* v sel bgcra~in re ure ct Zo 4o IOIO PSJ+

SR 3.S:~ 'f e. Flov Rate at Once/18 c.5 ~

sig months

/45 sf'.S.X,3 Thc RCIC pump shall SA 3.S.3. 9 deliver at least 600 gpm during each flow test.

2. If thereactor RCICS is inoperable, 5'~ > 53.Z f. Verify that nce/

the may remain in each valve Ac TloQ (manual, pover-operation for a period not to exceed days if thc operated, or HP is OPERABLE durin automatic) in the such time,. ppp f,R J'~ J~ in)ection flovpath 4JJ P that is not locked, If sealed, or other-

3. Specifications 3.5.F.1 or 3.5.F.2 are not met, ~ visc secured in position, is in its 5aQA~k and the reactor correc po ition.

shall be depressurized to ss than 150 psig vithin-N,~ hours.

cg.4 Qp,i Except that an automatic alvc capabl of automatic r urn to its ormal pos tion vhen a signal is prese may be in position for another mode of operation.

AMENOMENT Na. I 76 BFH Unit 2

3. 5/4. 5-15

~Cji'

~ '

5')Ci'ccrc'u 3. 5:3 UG 02 1989 Sg 8.S.>.

he core s ray system e, folloving surveillance PC HPCI or RCIC are requ red requirements shall be adhered to be OPERABLE, the scharge to assure that the discharge p ing from he pump d charge piping of the core spra of hest syst s to the st systems HPCI and CIC bloc valve sh 1 be fille are filled:

The suc on of th RCIC and HPCI Every month and prior to the pumps sha be alig ed to the testing of the RHRS (LPCI and condensate torage tank, an Containment Spray) and core e pressure suppress on chamber spray system, the discharge head tank shall normally be aligne piping of these systems shall to serve the discharge piping of be vented from the high point the RHR and CS pumps. The and vater flav determined.

condensate head tank may be used to serve the RHR and CS discharge 2~ Folloving any period vhere piping if the PSC head tank is unavailable. The pressure the LPCI or core spray systems have not been required to be indicators on the discharge of the OPERABLE, the discharge piping RHR and CS pumps shall indicate of the inoperable system shall ot less than listed btlov. be vented from the high point prior to the return of the Pl-75-20 48 psig s stem ta servict Pl-75-48 48 psig g) gs a.)

Pl-74-51 48 psig Whenever the CI or RCIC Pl-74-65 48 psi system is lined up to take suction from the condensate storage tank, the discharge piping of the CI an RCIC e v ed fram t high po of the s tern and voter lov ob erve on a monthly See X,q4<f'c~~io ~or C4 pg basis.

4r 8P N ISTIC

4. When t e an t e CSS are required to be OPERABLE, the pressure indicators vhich monitor the discharge lines shall be monitored daily and the pressure recorded.

~

BFH 3.5/4.5-17 AMEHbMENTHg. T6g Unit 2 PAGE~O

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

Cl

~<<~ <'~ho B.S.3 FEB 0 7 l991 3.5.E essu e Coolant In ection 4.S.E i h ressure Coolant In ectio S st PCIS 4.5.E.1 (Cont'd)

e. Flow Rate at Once/18 150 psig months The HPCI pump shall 5 cd +iL5+jg'gg'on fia deliver at least 5000 gpm during each flow rate test.

Ch+Qc5 Pnu BPn/ ]5y5 3 5.l f. Verify that Once/Month each valve (manual, power-operated, or automatic) in the injection flow-path that is not locked, sealed, or otherwise secured in position, is in its correct* position.

2. If the HPCI system is 2. No additional surveillances inoperable, the"reactor may are required.

remain in operation for a period not to exceed 7 days, provided the ADS, CSS, RHRS (LPCI), and RCICS are OPERABLE.

3. If Specifications 3.5.E.l

• Except that an automatic or 3.5.E.2 are not met, valve capable of automatic an orderly shutdown shall return to its ECCS position be initiated and the when an ECCS signal is reactor vessel pressure present may be in a shall be reduced to 150 position for another mode psig or less within 24 of operation.

hours.

Lco The RCICS shall be OPERABLE 1. RCIC Subsystem testing shall X5.3 whenever there is irradiated be performed a follows:

fuel in the reactor vessel A~or and the reactor vessel SP,g,g3.5 a. Simulated Auto- Once/18

%Plica'ikj pressure is above 150 psig, matic Actuation months except in the COLD SHUTDOWN Test or as specified in A h4w CONDITION 3.5.F.2. OPERABILITY shall ~nap sl s.S.~.s yg p BFN Unit 3

<>Rsed.

Spy g 3

~ Q~

3.5/4.5-14 AMBDMEHTNO,

S s+~<;~+ ~ -~ NUV a+ ious HS FOR OPE be determined vithin 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 5'gg g p p b Pump er t 4f'~~ after reactor steam pressure OPERABILZ1Y Specifi reaches 150 psig from a COLD ation SC3.g,3.9 COHDITIOH r a t at e y .O.MM PRI TO S RTUP usi an auxil st am sup ly. . M tor-Operate r Va e Sp cifi-OPE ILITY cat n 1.0.

Sg 3,g,pp d. Flov Rate at Once orma rea to rpo5rd go& v sel oper ting sP. w,s;z.s pr sur zo+o fo io t'so c)

SR Z.S.P.

Flov Rate at Once/18 q sig months C rgb l.6 The RCIC pump shall

<CrS,a.> deliver at least 600 gpm Sg3 during each flov test.

2. If the RCICS is inoperable, the reactor may remain in Slt 'R 5.xz f. Verify that each valve

'ce/

operation for a period not (manual, pover-to exceed days ifdurin the operated, or automatic) in the Jq HPCIS is OPERABLE such time. ripe/ '~md'atcl in)ection flovpath L.z

3. If Specifications 1

3.5.F.1 Br'n ~3 ih f2hc g that is not locked, sealed, or other-or 3.5.F.2 are not met, ee- vise secured in position, is in its D~~d-and the reactor correc sition.

shall be depressurized to s less than 150 psig vithin 2A hours.

3L >R'ua,'l H

• cept hat a aut atic v ve c able f aut matic re urn t its n rmal po tion en a igna is pre ent ma be in posi ion fo anoth r mo of operation.

~ J BFN Unit 3 3.5/4.5-15 AMENDMENT HO. 144

~+4 Pmfion 3.5.3 NY i 9 894

~RE.

WAmeovos- he core spray systems The following surveillance CI o C C are equired requirements shall be adhered to b OPERAB E, t disc arge to assure that the dis harge L.Al pipi from t e p disc arge pipin of'he core spray of th se syst s to the la t systems, LPCI, HPCI, and RCIC block lve s ll be ille are x e e sucti n of th R~C and HPC Every month and prior to the p s shal be ali ed to t e testing of the RHRS (LPCI and con sate s ra e t k Containment Spray) and core the pressure suppression chamber spray systems, the discharge ,

head tank shall normally be piping of these systems shall aligned to serve the discharge be vented from the high point piping of the RHR and CS pumps. and water flow determined.

The condensate head teak may be used to serve the RHR and CS 20 Following any period where the discharge piping if the PSC head LPCI or core spray systems tank is unavailable.. The have not been required to be pressure indicators on the OPERABLE, the discharge piping discharge of'he RHR and CS pumps of the inoperable system shall shall indicate not lees than be vented from the high point listed below. prior to the return of the system service.

Pl-75-20 48 psig Pl-75-48 S~RB. 5.3 3 Whenever the 48 psig PCI RCIC Pl-74-51 48 peig system is lined up to take Pl-74-65 48 psig suction from the condensate storage tank, the discharge pi iag of the CI an RCIC e yea e rom g e bligh gee 3'uSb4ecaW< fpr Q)g,~~~ poin of Qe s nK wate For Sg'H 4 5g p low o serve on a monthly bas s.

4. When e RHRS and the CSS ar required to be OPERABLE, the pressure indicators which monitor the discharge lines shall be monitored daily and the pressure recorded.

BFN 3.5/4.5-17 NENOMENT tt0. I7 B Unit 3 PAGE~OF~

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.3 - RCIC SYSTEM ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

A2 The Frequency of "Once/month" has been changed to "31 days." The Frequencies of "Once/3 months" and "Per Specification 1.0NH" have been changed to "92 days." Since the proposed frequencies are equivalent, this change is considered administrative.

A3 Notes allowing actual vessel injection to be excluded from this test (simulated automatic actuation test) have been added to proposed SR 3.5.3.5. Since the current requirements state the test is "simulated" (i.e., valve actuation and vessel injection are inherently excluded),

this allowance is considered administrative in nature.

A4 Surveillance Requirements for HOV operability that are required by the Inservice Testing Program have been removed from individual Specifications. This change is considered administrative in nature since these requirements remain in the IST Program which is defined by proposed Specification 5.5.6.

A5 The flow tests for the RCIC System are performed at two different pressure ranges such that system capability to provide rated flow is tested at both the higher and lower operating ranges of the system.

Since the reactor steam dome pressure must be &20 psig to perform SR 3.5.3.3 and &50 psig to perform SR 3.5.3.4, sufficient time is allowed after adequate pressure is achieved to perform these tests. This is clarified by a Note in both SRs that state the Surveillances are not BFN-UNITS 1, 2, 5 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.3 - RCIC SYSTEM required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after the specified reactor steam dome pressure is reached. CTS 3.5.F. 1 already contains the context of the Note for the low pressure flow rate test. This is also consistent with interpretation of the current technical specification requirement for the high pressure flow rate test which is currently not modified by a Note.

A6 The clarifying information contained in the "*" footnote has been moved to the proposed Bases for SR 3.5.3.2. The intent of the surveillance is to assure that the proper flow paths will exist for RCIC System operation. The Bases clarifies that 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. Moving this clarifying statement to the Bases is considered administrative in nature.

A7 A finite Completion Time has been provided to verify HPCI OPERABILITY.

the new time is immediately and is considered administrative since this is an acceptable interpretation of the time to perform the current requirement.

~ A8 CTS 3.5.F.3 requires the reactor to be depressurized to less than 150 psig when CTS 3.5.F. 1 and 2 cannot be met, while CTS 3.5.F. 1 requires RCIC to be OPERABLE when reactor vessel pressure is above 150 psig.

Proposed Required Action B.2 requires the vessel to be depressurized to x 150 psig. Since the intent of CTS is the same even though the CTS shutdown statement does not state "equal to," the addition of this requirement is considered administrative.

TECHNICAL CHANGES - MORE RESTRICTIVE An additional requirement is being added that requires the plant to be in MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This change is more restrictive because it stipulates that the reactor shutdown be completed much earlier than would be required by the existing specification (CTS 3.5.F.3). CTS require a shutdown to < 150 psig within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> but do not stipulate how quickly NODE 3 must be reached. Reference Comment L3 which addresses the less restrictive change of being ~ 150 psig in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> rather than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

BFN-UNITS 1, 2, 5 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.3 - RCIC SYSTEM TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" LAl The details relating to system design and purpose have been relocated to the Bases. The design features and system operation are also described in the FSAR. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in proposed BFN ISTS Section 5.0 and changes to the FSAR will be controlled by the provisions of 10 CFR 50.59. System operability determination, as described in the Bases and SR 3.5.3. 1, will ensure maintenance of filled discharge piping.

LA2 The details relating to methods of performing surveillance test requirements have been relocated to the Bases and procedures. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in proposed BFN ISTS Section 5.0 and changes to the procedures will be controlled by the licensee controlled programs.

LA3 CTS 3.5.F.1 specifically states that RCIC Operability can be determined prior to startup by using an auxiliary steam supply in lieu of using reactor steam after reactor steam dome pressure reaches 150 psig.

Details of the methods of performing this surveillance test requirement have been relocated to the Bases and procedures. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in proposed BFN ISTS Section 5.0 and changes to the procedures will be controlled by the licensee controlled programs.

"Specific" Ll The phrase "actual or," in reference to the automatic initiation signal, has been added to the surveillance requirement for verifying that the RCIC System actuates on an automatic initiation signal. This allows satisfactory automatic system initiations for other than surveillance purposes to be used to fulfill the surveillance requirements.

Operability is adequately demonstrated in either case since the RCIC System itself can not discriminate between "actual" or "simulated."

L2 This change proposes to extend the current allowed outage time for the RCIC System from 7 days to 14 days. The 14 days are allowed only if the HPCI System is verified Operable immediately. Loss. of the RCIC System will not affect the overall plant capability to provide makeup inventory BFN-UNITS 1, 2, 5 3 3 ~

at high reactor pressure since the HPCI System is the only high pressure system assumed to function during a LOCA. However, the RCIC System is PAQE J pF ~ Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.3 - RCIC SYSTEM the preferred source of makeup for transients and certain abnormal events with no LOCA (RCIC as opposed to HPCI is the preferred source of makeup coolant because of its relatively small capacity, which allows easier control of the RPV water level). The 14 day completion time is also based on a reliability study that evaluated the impact on ECCS availability (Memorandum from R. L. Baer (NRC) to V. Stello, Jr. (NRC),

"Recommended Interim Revisions to LCOs for ECCS Components," Oecember 1, 1975). Because of similar functions of HPCI and RCIC, and because HPCI is capable of performing the RCIC function, the allowed outage times determined for HPCI can be applied to RCIC. This change is consistent with NUREG-1433.

L3 The time to reduce reactor steam dome pressure to a 150 psig has been extended from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This provides the necessary time to shut down and cool down the plant in a controlled and orderly manner that is within the capabilities of the unit, assuming the minimum required equipment is OPERABLE. This extra time reduces the potential for a unit upset that could challenge safety systems. In addition, a new (more restrictive) requirement to be in MODE 3 (Hot Shutdown) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been added (See Comment Ml above). These times are consistent with the BMR Standard Technical Specifications, NUREG 1433.

L4 Existing Surveillance Requirement 4.5.E. l.d requires verification that RCIC is capable of delivering at least 600 gpm at normal reactor vessel operating pressure. The proposed surveillance, SR 3.5.3.3, requires verification of a minimum 600 gpm RCIC flow rate with reactor pressure

~ 920 psig and < 1010 psig. The RCIC performance test at high pressure is the second part of a two part test that verifies RCIC pump performance at the upper and lower end of the range of steam supply and pump discharge pressures in which the RCIC pump is expected to perform.

Performance of the RCIC test at both ends of the expected operating pressure range confirms that the RCIC pump and turbine are functioning in accordance with design specifications. The ability of the RCIC pump to perform at normal reactor vessel operating pressure has already been demonstrated. A small decrease in the pressure to as low as 920 psig at which the performance to design specifications is verified will not affect the validity of the test to determine that the pump and turbine are still operating at the design specifications.

L5 Existing Surveillance Requirement 4.5.F. l.e requires verification that RCIC is capable of delivering at least 600 gpm "at 150 psig reactor steam pressure." The proposed surveillance, SR 3.5.3.4', requires verification of a minimum 600 gpm RCIC flow rate with reactor pressure BFN-UNITS 1, 2, 5 3 Revision 0

'

JUSTIFICATION FOR CHANGES BFN ISTS 3.5.3 - RCIC SYSTEM at 165 psig. This change is less restrictive because it could allow reactor operation at pressures up to 165 psig prior to performing the surveillance. Performance of RCIC pump testing draws steam from the reactor and could affect reactor pressure significantly. Therefore, RCIC pump testing must be performed when the Electro-Hydraulic Control (EHC) System for the main turbine is available and capable of. regulating reactor pressure. Operating experience has demonstrated that reactor pressures as high as 165 psig may be required before the EHC system is capable of maintaining stable pressure during the performance of the RCIC test.

The RCIC performance test at low pressure is the first part of a two part test that verifies RCIC pump performance at the upper and lower end of the range of steam supply and pump discharge pressures in which the RCIC pump is expected to perform. Performance of the RCIC test at both ends of the expected operating pressure range confirms that the RCIC pump and turbine are functioning In accordance with design specifications. The ability of the RCIC pump to perform at the lowest required pressure of 150 psig has already been demonstrated. A small increase in the pressure at which the performance to design specifications is verified will not significantly delay or affect the validity of the test to determine that the pump and turbine are still operating at the design specifications.

L6 CTS 3.5.F. 1 requires operability to be determined within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reactor steam dome pressure reaches 150 psig from a COLD CONDITION. The allowance for reactor steam dome pressure and flow to be adequate is based on the need to reach conditions appropriate for testing. The existing allowance to reach a given pressure only partially addresses the issue. This pressure can be attained, and with little or no steam flow, conditions would not be adequate to perform the test - potentially resulting in an undesired reactor depressurization. The proposed change recognizes the necessary conditions of steam flow and minimum pressure as well as a maximum pressure limitation and provides consistency of presentation of these conditions. The point in time during startup that testing would begin remains unchanged. The change simply changes when the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> clock for performing the test must begin and permits testing to be completed in a reasonable period of time.

BFN-UNITS 1, 2, L 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.5 - ECCS AND RCIC SYSTEM BASES The Bases of the current Technical Specifications for this section (3.5.A, B, E, F, G, H, and 4.5) have been completely replaced by revised Bases that reflect the format and applicable content of proposed BFN-UNIT 1, 2,'and 3 ISTS Section 3.5, consistent with NUREG-1433. The revised Bases are as shown in the proposed BFN-UNIT 1, 2, and 3 Bases.

BFN-UNITS 1, '2, 5 3 Revision 0 pAGF l

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

J S pdCiliCcyhon 7,C, (,/

FEB 2 ames 2.a. Primary containment 4'/~~Pl'4 4aca~y shall be Ezo gy,/,] maintained at all times Primary co tainment n trogen vhen the reactor is critical consumpti n shall be

"/Pl <'~nb'ily or vhen the reactor vater monitor to etermin the temperature is above 212 F averag dail nitrog and fuel is in the reactor cons tion or the ast vessel cep v e 24 h urs. cessi leakage erforming "open vessel" is ndicat d by a physics tests at pover co umpti n rate f > I of levels not to exceed e pr ry con ainm t free 5 MW(t). A lume er 24 ours

b. Primary containment corre temper ed f dryv ture press re, ll integrity is con rmed if venti op atio ) at e maxim allov le 49.6 psig Corr cted t in egrated eakage rate, no 1 d ell perati Lay does no't exceed the pressur of 1. psig, this equi lent of pere t of value s 542 CFH. this the pr ry co ainmen value is exc eded, e volume r 24 h rs at the action spec fied in 49.6 psi design asis 3.7.A.2.C shall be taken.

accident essure P '. 5'R3-4 ~ ~ ~. <

Ce If 2 makeup to the rimary in accordance vith the Primary ontai ent ave aged ver Containment Leakage Rate 2 hours (correc ed f Testing Program.

pr ssure, tempera ure, d ven ing op ations exc ds 542 CFH, it must b red ce to < 42 SC vithin ~ ours

<gioNpg or the reactor shall be emplaced in Hot Shu de RGTl&t 6 )vithin the next 3k hours

~4 <<id'hu>~

~2 ~n34ho, s BFK 3.7/4.7-3 NENOMEg gg, pp8 Unit 1

FE822~i PAGE~OF 3.7/4.7W

DF<c4'c'phon 3',(., l, 1 FEB 8 2 199j Pr,(.cour~

3.7/4.7-5 hMENOMENT NO. 228 BFS Unit 1

~ ~ ~

<R 3.R.4 ~

I'e I

g. Perform required local leak rate tests, nc u ng t e r mary containment air lock leakage rate testing n accor ance v t t e Primary Containment Leakage Rate Testing Program.

Yush4caÃon gz PQ~y Eote: An inoperable air lock 0< 8gaJ ]Spy door does not invalidate the previous successful performance of the overall air lock leakage test.

The acceptance criteria for air lock testing are: (1)

Overall air lock leakage rate is g (0.05 La) vhen tested at g Pa. (2) For door seal leakage, the overall air lock leakage rate is g (0.02 La) vhen the air lock is pressurized to (g 2.5 psig for at least 15 minutes).

BFH 3.7/4.7-6 AMENDMENT NL? P. 8 Unit 1

(1) Ef at ny time it is termined hat t criteri of 4.7.A.2.g 's exceeded, repairs shall be initiated immediatel (2) Zf conformance to the criterion of pc.T(oN A 4.7.A.2.g is not demonstrated within ~i hours.

following detection of excessive local in Hob' in leakage, the

/s. 0c~rs I ~>>< '/ reactor shall be

>n gg A~~

until repairs are effected and the local leakage meets the acceptance criterion as demonstrated by etest.

The mann s earn one isolation valves shall be tested at a pressure of 25 psig for leakage during each refueling outage. Zf the leakage rate of 11.5 scf/hr for any one main steamline isolation valve is exceeded, repairs and retest shall be performed to correct the condition.

BFN 3.7/4.7-8 Unit 1

When e prima conta ent's erti the con inment s continuo ly monit red ll for gross eakage b viev of e inerti reg rements. This monit ing sys may be aken o t of se ice for nt e but s 1 be ret rned t service as soon pra icable.

The in rior su aces the d Il and t ab e the evel one foot belo the n anal vat line out de surfac of th torus elov th vater ine 1 be suall ins cted ope sting cle or de riorat on signs st ctur e vith par cul attention to pip conn tions and suppo s and or signs of dist ess or displacement.

BPS 3.7/4.7-9 Uait 1

3.7.k.4 (Cont'4) 4.7.4.4 (Coat'4)

c. so Cryvell-suppression "-ach vacuum breaka valve chamber vacuum breakers shall be inspect~ for may 'oe determined to be yroyer oyeratioa oi ="e yerable for opening. valve aaC LM in accordance vith Spec'ficat'on 1.Q.. C.

Q ~ gi ~ le li 2-d<<<<f Spec <<<<cac<<oas 3 ~ 7.k<<< ~ aq a tesc of the dr:ovel 3.7.4.4.b, or 3.7.4.4.c. to suppression chambe Scc cannot be met, the st~care shall be conducted W Chewy> W aait shaLL be placed in a daring each o B Ai ~F5 3AI. i COLD SHUTDOWNÃ CQ5D~ON in Lcc c Le Leaic rate Ls la ~og.

an orderly maaaer vithin 0.09 Lb/sec M yr~~

24 hours. containment acmosyhere vi "

1 ysi Cifie"mat'al 5.

a. Containment atmosphere shall be a. The yrimary .containment reduced to Less than 4X oxygen oxygea concentration shall vich aitrogea gas Curing reactor be measured and recorde4 yover oyeration vith reactor daily. The oxygea cooLant yressare above 100 ysig, measurement shall be ad)usted except as specified in 3 ~ 7.l<<5 <<b. to accoaat for the aacertainty of the metho4 used by adding a predetermined error faact'oa.

b. Vichia the 24 hoar period b. The methods used to measure subsequent to ylacing the reactor the primary containment in th>> RN NDl foLloving a shat- oxygen coaceatration shall Cova the coatainmeat atmosphere

~ be calibrated once every oxygen coacentracioa shall be refueling cycle.

reduced to Less than 4% by volume and maintained Ln this condition.

Deinerting may commence 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a shatCova ~

c. If plaat control air ts being used c. The coatroL air suyyly for the pneumatic coatroL valve to supply the yaeamatic coatrol system- inside primary coatainmcat, systes Laside the pzmaz7 the reactor shall aot ba started, coatainmeat shall be verif'ea i or Lf at yover, the reactor shall closed prior to reactor star= =

be brought to a COLD SHUTDOWN and monthly thereafter.

CQHDIT 05 vithia 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

d. If Specificatioa 3.7.A.5.a aad 3.7.4.5.b cannot be met, aa orderly shutdova shall be initiated aa4 the reactor shall be in a COLD SHUTDOWN COHDITIOI vithia 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

BFH 3.7/4 . 7-11 AMEi fOMENT NQ, y g g Unit 1 PAGE OF I

i UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP

Cthe *Op, Qe J ~ J 2eae Primary containment

&0 3.k.i,J maintained at all times contai ent nitrogen when the reactor is critical consum tion s 1 be A p )i cg b i li 4 or when the reactor water monit ed to d termine he temperature is above 212 F aver e daily itrog and fuel is in the reactor cons ption f r the 1 st vessel cept w 24 ours. cessive eakage er orming "open vessel" is ndicate by a H physics tests at power co umptio rate of > 2X of levels not to exceed t e prima contai ent free 5 M(t). 2 olume pe 24 hou

b. Primary conta nmen ntegri is confirme Sf'rimary if (correct tempera for d re, pre sure, venting operati ns) at ell t e max allo ble 49.6 p ig. Co rected to in egrate leakag rat , norma drywel opera ing La, does n t excee th pres re of .1 psi , this egu alent f2 pe ent f val is 54 SCFH. If this the imary ontai t val e is ceded, e volum per 24 ours the act on specified in 49.6 p ig desi basis 3.7.h.2.C shall be taken.

ccident pressure, P . ~ 7.C.(. l er e I rm leakage rate testing C~ If 52 makeup to the primary in accordance with the Primary con ainmen averag d over Containment Leakage Rate 24 urs (c recte for Testing Program pres ure, t eratu e, and venti opera ons) ceeds 542.

to S, SC it ithinA uced ours Alarm A /or the reactor shall be placed in Hot Shutdown Wlnpl 8 within the next hours d~hl Shu~a

'~ 36 hOl4CS hNENMENr NL 2c8 BFH 3.7/4.7-3 Unit 2

Sp<c jfirqQn Zi io. I> /

FEB 8 259s BFR 3.7/4.7W NENDMENT NC. 243 Unit 2 PAGE~o.. 'I

5f ecsP:c'crgon 9.6, (. I FES 2 2 1996 4 ~ ~ e t BFE 3.7/4.7-5 hMENOMENT NO. 243 Unit 2

FEB 22$ 9S

~ ~ ~ ~

A/3 3.4. lil

g. Perform required local leak rate tests nc u ng e primary containment air lock leakage rate testi in accordance w e Primary Containment Leakage Rate Testing Program.

Hote: kn inoperable air lock See ruse<'~Son 4r door does not c+~$ Ar /go zsTs invalidate the previous successful performance 3.o, I.~ of the overall air lock leakage test.

The acceptance criteria for air lock testing are: (1)

Overall air lock leakage rate is g (0.05 La) vhen tested at g Pa. (2) For door seal leakage, the overall air lock leakage rate is g (0.02 La) vhen the air lock is pressurized to (g 2.5 psig for at least 15 minutes).

NENDMENT No. 243 BFH 3. 7/4. 7-6 Unit 2 5

h: (1) If at any 'me it is determi that e crite on of 4.7 .2.g Is exceeded, repairs shall be initiated immediately.

(2) If conformance to the CT(ofJ p, criterion of 4.7.A.2.g is not demonstrated within

~ fAp4 hour& foilowing l detection of excessive local leakage, the reactor r~ HojX-: g i ~ l2 N~r~ shall b

+>>DC q; 3g 4o~rg until repairs are effected and the AC7)o~ B local leakage meets the acceptance criterion as demonstrated by retest.

The main steamline isolation valves shall be tested at a pressure of 25 psig for leakage during each refueling If the leakage'utage.

rate of 11.5 scf/hr for any one main steamline isolation valve is exceeded, repairs and retest shall be performed to correct the condition.

~ kQ MKgPJ ji(g)li~ g

~~ >+> isrs g .S./ g BFN 3.7/4.7-8 Unit 2 PAGE

j. o HmDar en the pr ry c tainment incr the ontainmena, shall be cont uously mo tored fo'r gr s leakage by reviev o the incr stem up r uircmen ~ This ear may bc taken ut of ~ rvice for maint a but be returned o serv ce as soon as pr ticable.

e interior fac s of e dzpwell to ab e the leve one f t bel the no eater line outside surfac of the t belcnr eater 1 shall be sually pected ch opera iIlg le for de rioration and signs struc al e vlth parti ar atten ion to ping acti and s rts for signs o'f d tres or displac t BPI 3.7/4.7-9 Unit 2

HOV 22 1888 5 acifica4iow E Co ( \

S'7 S

3.7.A.4 (Cont'd) 4.7.A.4 (Cont d

c. Tvo dryvel'-suppression c. Each vacuum brcake" valve chamber vacuum breakers shall bc inspected'or may be determined to be proper operation of ="e inopc abLe for opening. valve and limit switches in accordance with Specification L.O.HC.

gp q.Q.).

~

v~dÃicJ~

d. If Specifications be3.7.A.4.a d. A leak test of the d Jvell to suppression chamber See .b, or .c cannot met, thy CQCs+AQ uait shall be placed in a tructure shall be conducted SAI isTS g.to I. 7 Cold Shutdovn condition in during each an orderly manner vithin Pl Accc table e rare ~pg, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. 0.09 1 scc o pr mazy coatainmcat atmosphere with SEE KcCSr tFiCArcrg ~g CAAHQ~ si differential

>R QFN <srs g.c,g~

0

a. Coatainmeat atmosphere shall bc a. The primary coataiameat reduced to less thaa 4X oxygen oxygen concentration shal'e vith nitrogea gas during reactor measured and recorded pover operation Mich reactor daily. The oxygen

.coolant pressure above 100/psig, measurement shall bc ad)usted except as specified ia 3.7.A.S.b. to account"for the uncertainty of the method used by adding a predetermined error function.

b. Mithin the 24-hour period b. The methods used to measure subsequent to placing the reactor the primary containment in the RUH mode folloving a shut- oxygen concentration shall down, the containmeat atmosphere be calibrated once every oxygen coaceatration shall bc refueling cycle.

reduced to less than 4X, by volume and maintained in this condition.

Deinerting may commeace 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a shutdown.

c. If plant control air is being used c. The control air supply valve for the pneumatic control to supply the pneumatic control system inside primary coatainment, system inside the primary the reactor shall aot be started, containment shall be verified or if at pover, the reactor shall closed prior to reactor startup and monthly thereafter.

bc. brought to a Cold Shutdovn condition vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

d. If Specification 3.7.A.S.a and 3.7.A.S.b cannot bc met, an orderly shutdovn shall be initiated and the reactor shall bc in a Cold Shutdown condition vithin 24 hours.

BFH 3.7/4.7-11 ph3c'gMg! T t'~C Unit 2 PAGE~OP

'

UNIT 3 CURRENT TECHNICAL SP ECIF ICATION MARKUP

5 Pc 4 i Ci cp on, g ]

2.a. Primary containment maintained at all times Primary c taiament nitrogen whea thc reactor is critical coasumpt n shall or when the reactor vatcr monitor d to dete ine thc temperature is above 212 F averag daily,ni rogen and fuel is in the reactor cons ption fo the las vessel ccpt w i e 24 urs. Ex essivc 1 ge pcrformiag "open vessel" is ndicate y a N2 physics tests at pover c umptio rate of 2X of levels not to exceed e prima conta ent frcc MW t volume r 24 hou (corrc cd for ell

b. Primary ontaiamcnt ature, p ssure, 'cmpe i tcgrity s confi ed if vcn ag opera ioas) a orrecte to th maxim allovab e 49 psig.

in grated eakagc r te, n 1 d ell oper iag La, does not exceed t e pressure f 1.1 ps g, this equi alent of 2 percen of value is 542 SCFH If this the p imary co taiament value i excccd , thc volume er 24 h urs at t e action specifi in 49.6 ps g design basis 3.7.k.2.c sha be taken.

ccident P ~ S 34 ~

er leakage rate testing c If H2 makeup to e primary in accordance vith the Primary c ntaiam t aver d over Contaiamcnt Leakage Rate 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ( orrected or Testing Program.

pr sure, t peratur and vent ng opera ions) cx eds 542 S , it t bc reduce to < 5 SC vithin hours g or the reactor shall be

'8 Swithin in c, placed Hot Shutdovn the next

/2 hours.

~told Shukdoupn

>n 34 goer g BFS 3.7/4.7-3 lRNMNTNO. 2 03 Unit 3 PAGE OF

Sk<'4 0~ Z <

FEB 2 8 SSS NIENDhfQT NQ, P 03 BFR Unit 3 3.7/4.7W PA3E~OF~

eted NBIDMEÃF RLP 0 3 BPH 3.7/4.7-5 PAGE~OF Unit 3

g. Perform required local leak r eats nc u ng t e primary containment a r lo e rate testi in accordance v t t e Primary Containment Leakage Rate Testing Program.

Rote: An inoperable air lock door does not 5ee 3~g40; rabin&< invalidate the previou successful performance Ch~qcs &r SAN Xsrs Zt..l.< of the overall air lock leakage test.

The acceptance criteria for air lock testing are: (1)

Overall air lock leakage rate is g (0.05 La) vhen tested at g Pa. (2) For door seal leakage, the overall air lock leakage rate is g (0.02 La)

@hen the air lock is pressurized to (g 2.5 psig for at least 15 minutes).

BFR 3.7/4.7-6 NBIOMENT HO. 2 03 Unit 3 PAaE

h. (1) If at a time it is d ermined that the criterion o 4.7.A.2.g is exceeded, repairs shall be 3.nitiated immediately.

(2) f conformance to the criterion of jhow'IorJ A 4.7.A.2.g is not demonstrated within

~ hour> following detection of excessive local eakage, the pl~ 3 j~ /2 &Owed reactor shall be

~Ho05 Q/~ 2C,A-<<

until repairs are

+vta4 8 effected and the local leakage meets the acceptance criterion as demonstrated by etest.

The main steamline isolation valves shall be tested at a pressure of 25 psig for leakage during each refueling outage. If the leakage rate of 11.5 scf/hr for any one main steamline isolation valve is exceeded, repairs and retest shall be performed to correct the condition.

5j?t j~g jiCiGaf>ow 4~ C44 p+

AI BFN l>7-s g.z./.3 BFN 3.7/4.7-8 Unit 3 PAGE

C t the pr ry con ainment i inerte thc ntainment hall contin usly mo ored for gros leakage eviev of e inert tea aike r remcnts. This monit rial sys may bc taken t of sc ce for maint e but shall be returned t service as soon as yrac icable.

The interior surfaces of the dryvcll and torus above the level onc foot belov the normal vater line and outside surfaces of the torus belov the water linc shall be visually inspected each operating cycle for deterioration and any signs of structural d4RLgc vith particular attention to pipiag connections and.

suyports and for signa of dis'tress or displacement.

BPH 3.7/4.7-9 Unit 3

0 3.7.A.4 (Cont'd) 4.7.A.4 (Cont'd)

c. Tvo dryvcll-suppression C~ Once each operating cycle, chamber vacuum breakers each vacuum breaker valve may be determined to be shall be inspected for inoperable for opening. proper operation of the valve and limit svitches in accordance with Specification 1.0.MM.

d. If Specifications 3.7.A.4.a, d. A leak test of thc dryvell to suppression chamber 3.7.A.4.b, or 3.7.A.4.c, Sec '$45f&~og cannot be met, the structure shall be conducted For chpggs +r unit shall be placed ur ng a o 8cN fsrs 34(,7 in a Cold Shutdown Acce table leak rate is condition in an orderly .09 lb/sec o pr ary manner vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. containment atmosphere vit 1 si differential.

5. 0 5. 0

a. Containment atmosphere shall be a. The primary containmcnt reduced to less than 4X, oxygen oxygen concentration shall vith nitrogen gas during reactor be measured and recorded paver operation vith reactor daily. The oxygen coolant pressure above 100/psig, measuremcnt shall be ad)usted except as specified in 3.7.A.5.b. to account for the uncertainty of the method used by adding a predetermined error function b.. Within the 24-hour period b. The methods used to measure subsequent to placing the reactor the primary containmcnt in the RUR mode folloving a shut- oxygen concentration shall down, the containment atmosphere be calibrated once every oxygen concentration shall bc rcfucling. cycle.

reduced to less than 4X by volume and maintained in this condition.

Deinerting may commence 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a shutdown.

c. If plant control air is being used c. Thc control air supply valve for the pneumatic control to supply the pneumatic control system inside primary containmcnt, system inside the primary the reactor shall not be started, containmcnt shall be verified or if at pover, the reactor shall closed prior to reactor sr.artup and monthly thereafter.

bc brought, to a Cold Shutdown condition vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Ce 3'u5hCs'cation fir <~g<f If the specifications of 3.7.A.5.a ~ BPu ~5'r> Z.G.3.2.

through 3.7.A.S.b cannot be mct, an orderly shutdown shall bc p~cE~oF 0 initiated and thc reactor shall bc in a Cold Shutdown condition ithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

BFH 3.7/4.7-11 Unit 3

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.1 - PRIMARY CONTAINMENT ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

A2 The definition of PRIMARY CONTAINMENT INTEGRITY has been deleted from the proposed Technical Specifications. In its place the requirement for primary containment is that it "shall be OPERABLE." This was done because of the confusion associated with these definitions compared to its use in the respective LCO. The change is editorial in that all the requirements are specifically addressed in the proposed LCO for the primary containment along with the remainder of the LCOs in the Containment Systems Primary Containment subsection (e.g., air locks, isolation valves, suppression pool). Therefore, the change is purely a presentation preference adopted by the BWR Standard Technical Specifications, NUREG 1433.

A3 CTS 4.7.A.2.k requirements for visual inspection of the drywell and torus surfaces are also contained in 10 CFR 50, Appendix J. These regulations require licensee compliance and cannot be revised by the licensee. These details of the regulations within CTS are repetitious and unnecessary. Therefore, the details also found in Appendix J have been deleted. This is considered a presentation preference and as such is considered an administrative change.

BFN-UNITS 1, 2, 8L 3 Revision 0 PAGE~OF

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.1 - PRIHARY CONTAINHENT A4 CTS 3.7.A.2.b provides acceptance. criteria for integrated leak rate testing, which is redundant to those contained in Primary Containment Leakage Rate Testing Program (CTS 6.8.4.3) requirements. The definition of L. is provided in proposed BFN ISTS 1. 1 and need not be repeated here. As such, this deletion is considered administrative.

A5 The acceptance criteria for the leak test of the drywell to suppression chamber structure has been changed from 0.09 lb/sec of primary containment atmosphere at 1 psid to 0.25 inches of water for 10 minutes.

Since these values are equivalent this is considered an administrative change.

A6 CTS 4.7.A.2.h(1) requires repairs to be initiated immediately when it is determined the criterion of 4.7.A.2.g is exceeded. CTS 4.7.A.2.g requires LLRTs to be performed in accordance with the Primary Containment Leakage Rate Testing Program (CTS 6.8.4.3). CTS 4.7.A.2.h(2) then allows 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to demonstrate 4.7.A.2.g can be met following detection of excessive local leakage. Since repairs are typically initiated immediately and proposed BFN ISTS ACTION A will only allow 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />"to restore primary containment to OPERABLE status prior to requir'ing the initiation of a shutdown (reference Justification H2 below), CTS 4.7.A.2.h(1) has been deleted.

TECHNICAL CHANGES - NORE RESTRICTIVE Hl CTS 3.7.A.2.a requires the primary containment to be OPERABLE at all times when the reactor is critical or when the reactor water temperature is above 212'F and fuel is in the vessel. The proposed BFN ISTS 3.6.1.1 applicability is HODES 1, 2, and 3. This is more restrictive since CTS does not require the primary containment to be OPERABLE when in HODE 2, not critical and < 212'F.

H2 Proposed Action A is more restrictive than CTS 3.7.A.2.c since the time allowed to reduce excessive nitrogen leakage prior to initiating a shutdown has been reduced from 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The time allotted to place the unit in Hot Shutdown (HODE 3) has been reduced from 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Proposed Action B requires the unit to be placed in Cold Shutdown (HODE 4), whereas, CTS 3.7.A.2.c only requires the unit to be placed in Hot Shutdown.

In addition, CTS 4.7.A.2.h.(2) allows 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to demonstrate conformance to Appendix J following detection of excessive local leakage BFN-UNITS 1, 2, 5 3 Revision 0 PAGE R op 3

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.1 - PRIMARY CONTAINMENT and then requires a plant shutdown if conformance can not be demonstrated. CTS does not specify a completion time for shutdown and does not specify whether shutdown is to the Hot or Cold Shutdown Condition. The Proposed Actions A and B are more restrictive since they only allow 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to restore primary containment and then require the unit be in MODE 3 in 12 and MODE 4 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" LA1 The details relating to routine monitoring of plant status and operations parameters that reflect primary containment operability and the methods of performing this monitoring have been relocated to the Bases and procedures. Acceptance criteria for primary containment N, leakage (i.e., makeup consumption) have been relocated to procedures.

Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in proposed BFN ISTS Section 5.0 and changes to the procedures will be controlled by the licensee controlled programs.

LCl The conti nuous leak rate monitor does not necessarily relate directly to primary containment operability. In general, the BWR Standard Technical Specifications, NUREG 1433, do not specify indication-only or alarm-only equipment to be OPERABLE to support operability of a system or component. Control of the availability of, and necessary compensatory activities if not available for, indications, monitoring instruments, and alarms are addressed by plant operational procedures and policies.

Therefore, the continuous leak rate monitor, and associated alarm surveillances and actions will be relocated to a licensee controlled document. Any changes will require a 10 CFR 50.59 evaluation.

BFN-UNITS 1, 2, &

3'AGE QP~ Revision 0

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

0 SAci 0i c~

FEB 2 2 1996 2.a. Prima conta nment 2. te ated Leak Rate estf inte ity s aincd ll be t all mai imes Primary containment nitrogen vh the cactor is cr ical consumption shall bc o vhen e re tor v ter monitored to determine the At cmpcr urc i abov 21 'P average daily'itrogen and f el is n the ea or consumption for the last vcss cxc t wh e 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Excessive leakage perf rmi "op vcs el" is indicated by a H2 physics sts a po er consumption rate of > 2X of levels not to exceed the primary containment free 5 t%(t). volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrected for dryvell

b. Primary containment temperature, pressure, and integrity is confirmed thc maximum allovable if venting operations) at 49.6 psig. Corrected to integrated leakage rate, normal drywell operating La, does not exceed the pressure of 1.1 psig, this equivalent of 2 percent of. value is 542 SCPH. If this thc primary containment value is exceeded, the volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at thc action specified in, 49.6 psig design basis 3.7.L.2.C shall be taken.

accident pressure, Pa.

Perform leakage rate testing

c. If H2 makeup to the primary in accordance vith the Primary containment avcragcd over Containment Leakage Rate 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrected for Testing Program.

pressure, temperature, and venting operations) exceeds 542 SCFH, it must bc reduced gee guc+4'mb'+n Ar Chanyeg to c 542 SCFH vithin 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or thc reactor shall be 4i BF~ iSVS 3.C..i.l placed in Hot Shutdovn vithin the next 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.

l-co p,5,1,2. 8 lic4b.lip PI<RsR ACT'Iow5 A+g A]

t'<opsy AJoH gg ~ /b;17oAS W3 'Af$4 SR 3,g, t, f

~AGE OF BFH 3.7/4.7-3 Unit 1

~ ~ ~ ~

SR3.a.(.g. I

g. Perfo required local leak rate tests including t e Sce XusHC'cab'on Qr @~ay primary containment air lock leakage rate testing in

'&< B~W tST5 accordance with the Primary Containment Leakage Rate Testing Program.

Rote: An inoperable air lock 5g 3 g i g door does not invalidate the previous successful performance of the overall air lock leakage test.

The acceptance criteria for air lock testing are: (1)

Overall air lock leakage rate is g (0.05 La) when tested at g Pa. (2) For door seal leakage, the overall air lock leakage rate is g (0.02 La) when the air lock is pressurized to (g 2.5 psig for at least 15 minutes).

<<e ~~Wi'ca~n Qi C4~s 8FN ) ST$ 5,g,I~

BFH 3 '/4.7-6 AMENDMENT NQ. 228 Unit 1 PAGE~QF g.

Zf at any ime i" is det ined t at the iterio of 4.7.A.2.g exceeded, repairs shall be initiated immediately.

(2) Ef conformance to the criterion of 4;7.A.2.g is not demonstrated within ho rs following 2 4 HZ detection of excessive local leakage, the eactor shall be

~~~ 3 I I24~

/Hop/ c/ gg ggg until repairs are effected and the local leakage meets the acceptance criterion as demonstrated by retest.

The main steamline isolation valves shall be tested at a prgssure of 25 psig for leakage during each refueling outage. Zf the leakage rate of 11.5 scf/hr for any one main steamline isolation valve is exceeded, repairs and retest shall be performed to correct the condition.

BFN P.7/4.7-8 Unit 1

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP

SPCCi4iCCrf)On "7 6- I-2 FE8 P, 2%6 2.a. Primary ontai ent 2.

integri y sha be mainta ned a all times Pr'imary containment nitrogen vhen e re tor is critical consumption shall be I or v en th react vat r monitored to dctcrmine the t cratu is a ve 2 2'F average daily nitrogen fuel s in e re ctor consumption for thc last v esel cept ile 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Excessive leakage pcrfo ng "op ves el" is indicated by a E2 physic tests at po er consumption rate of > 2X of level not to exceed the primary containment free volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrcctcd for dryvell

b. Primary containment temperature, pressure, and integrity is confirmed the maximum allovable if venting operations) at 49.6 peig. Corrected to integrated leakage rate, normal dryvell operating La, docs not exceed the pressure of 1.1 peig, this equivalent of 2 percent of value is 542 SCFH. If this thc primary containment value is exceeded, the volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at thc action spccificd in 49.6 peig design basis 3.7.k.2.C shall be taken.

accident pressure, Pa. ISTIC Perform lcakagc rate testing

c. If S2 makeup to thc primary in accordance vith thc Primary containment averaged over Containment Leakage Rate 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrected for Testing Program.

'rcssure, temperature, and venting operations) excccds 542 SCFH, it must be reduced to < 542 SCFH vithin 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />

~<~

A~

~~iWWn 4< C~C5 8FhJ or the reactor shall bc placed in Hot Shutdovn vithin the next 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.

ACO g, (o. t. 2 Ppp )) ~g; )', P f'no@i~< RCT<o~a /I > b Pno sea 4u4 I tg p Acr<o+5

]go g<J 5k'.6.lit 2 3.7/4.7-3 hMENMNr N. 2 c8 BFH Unit 2 PAGE R OP~

I:ES 8 2896 Ai

~ ~ ~ ~

58 3.b. I~ > ~ ~

g. Perform required local leak rate tests, includi the 5<c 5~~$ icqgan Qr C/ggg5 primary containment air lock leakage rate testing in Qr SPN l5i5 Z.6, l.l accordance vith the Primary Containment Leakage Rate Testing Program.

Hote: kn inoperable air lock door does not invalidate the previous successful performance

, of the overall air lock leakage test.

The acceptance criteria for air lock testing are: (1)

Overall air lock leakage rate is g (0.05 La) vhen tested at g Pa. (2) For door seal leakage, the overall air lock leakage rate is g (0.02 La) vhen the air lock is pressurized to (g 2.5 psig for at least 15 minutes).

Se'e Su5 tea'can'en Qr'kCi~gC'5 Ai 8<N l57< g.g.i~

NENDMENT N. 243 BFH 3.7/4.7-6 Unit o~~

2 pAGE X

~ r w>> n a.>>>,/

h. Ql) Zf at y time it i dete ined that the cri erion of 4.7.A.2.g i exceeded, epairs shall be initiated immediately.

(2) f'onformance to the criterion of Rpgu>l cA 4.7.A.2.g is not Acfi'p<<C. 2. d strated within ours following detection of P~pa~ excessive local RCy<<>> Q leakage, the reactor Ac.f>~C. I shall b shet-down In ~p~ 3

~ 2 He>>rj p go~

g until repairs are

~4 haul effected and the P,c, ripe local leakage meets b

the acceptance criterion as demonstrated by retest.

The main steamline isolation valves shall be tested at a pressure of 25 psig for leakage during each refueling outage. Ef the leakage rate of 11.5 scf/hr for any one main steamline isolation valve is exceeded, repairs and retest shall be performed to correct the condition.

SeC Xug$,'f;~p~ g pg hr 5/WIST~ 36 1..3 BFN Unit 2 3.7/4.7-8 PAGE~0 ~

0 UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

2.a. Prima ontainment 2. I e rated Leak Rate Testi int ity shal e ntained all times Primary containment nitrogen hen th eactor is itical consumption shall be or v the rea r vater monitored to determine the t'rature above 2 F average daily nitrogen fuel in the actor consumption for the last vessel cept v e 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Excessive leakage perf ing "o vessel" is indicated by a E2 p sics tes at pover consumption rate of > 2X of evels no to exceed the primary containment free

%l(t) volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrected for dryvell

b. Primary containment temperature, pressure, and integrity is confirmed if venting operations) at the maximum allovable 49.6 psig. Corrected to integrated leakage rate, normal dryvell operating La, does not exceed the pressure of 1.1 psig, this equivalent of 2 percent of value is 542 SCFH. If this the primary containment value is exceeded, the volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the action specified in 49.6 psig design basis 3.7.k.2.c shall be taken.

accident pressure, Pa.

Perform leakage rate testing

c. If H2 makeup to the primary in a'ccordance vith the Prima containment averaged over Containment Leakage Rate 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrected for Testing Program.

pressure, temperature, and venting operations) exceeds 542 SCFH, it must be reduced 5ee ~~+;4i ca fjon4r Chang to < 542 SCFH vithin 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> ts'~

or the reactor shall be 8@v 1ST'.C;I.I placed in Hot Shutdovn vithin the next 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.

~c. g.b, l. 2 I;i~b:l&

t'ro scd 4'TYPES 8 FB

~>+<<g Sole Jyg y +'o<S

%3 fno acA, Sk 3,k.l.l.

3.7/4.7-3 NBfDMNTgo. P g 3 BFS Unit 3 f'ACiE~QF~

5

g. Perform equ red local le rate tests, includi the 5'cc ~wSHAcafjon Qr PQ~ primary conta nment air lock

<~ 8<m t Srs z.c,.i.] leakage rate testing in accordance vith the Primary Containment Leakage Rate Testing Program.

Hote: An inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.

The acceptance criteria for air lock testing are: (1)

Overall air lock leakage rate is g (0.05 La) vhen tested at g Pa. (2) For door seal leakage, the overall air lock leakage rate is g (0.02 La) vhen the air lock is pressurized to (g 2.5 psig for at least 15 minutes).

sec WusA'C>cab'on 0) C~~

6R di=nr g 7S g, g.i~

NBlDMST HO. 2 03 BFR Unit 3 3.7/4.7-6 pAGE 3 OF~

SFe C i Pica on p. (. I - 2 h (1) at y ti it i dete ined hat th crit ion

4. A.2.g is exc ded, epair shal be in tiate immed atel 4euwcd (2) Zf conformance to l@hrn C.2. the criterion of 4.7.A.2.g is not demonstrated within hours following Aft'SC4 etection of 4Abn Co) cxcessivc local leakage, the reactor hall

)trio v repairs are i n o~ 3 effected and th g local leakage me OC Q I the acceptance criterion as demonstrated by QZ retest.

The main steamline isolation valves shall See 3iu+g;c~gn be tested at a pressure Foe ('-~gg)cg Qg, of 25 psig for leakage 8<< tsTs S.b.l.3 during each refueling outage. Zf the leakage

<< ~)K sc'cking rate of 11.5 scf/hr for any one main steamline isolation valve is exceeded, repairs and retest shall bc performed,to correct thc condition.

BPR Unit 3 3.7/4.7-e PAGE~~" ~

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.2 - PRIMARY CONTAINMENT AIR LOCK ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore,

-understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

A2 CTS 4.7.A.2.h(1) requires repairs to be initiated immediately when it is determined the criterion of 4.7.A.2.g is exceeded. CTS 4.7.A.2.g requires LLRTs to be performed in accordance with the Primary Containment Leakage Rate Testing Program (CTS 6.8.4.3). CTS 4.7.A.2.h(2) then allows 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to demonstrate 4.7.A.2.g can be met following detection of excessive local leakage. Since repairs are typically initiated immediately and proposed Required Action C. 1 for 3.6.1.2 requires action be initiated to evaluate the primary containment overall leakage rate using the current air lock results and ACTION A of ISTS 3.6.1. 1 will only allow 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to restore primary containment to OPERABLE status prior to requiring the initiation of a shutdown (reference Justification M2 for Specification 3.6. 1.1), CTS 4.7.A.2.h(1) has been deleted.

TECHNICAL CHANGES - MORE RESTRICTIVE The current requirements for the air lock are located within the primary containment TS requirements. The current definition of primary containment integrity requires only one air lock door to be closed and sealed (i.e., the seal mechanism intact and sealing the door). Thus, no actions are required if one door is inoperable provided the other door is OPERABLE, since primary containment integrity only requires the one door. The proposed LCO requires the entire air lock to be OPERABLE, BFN-UNITS 1, 2, L 3 Revision 0

JUSTIFICATION FOR 3.6.1.2 -

CHANGES'FN ISTS PRIHARY CONTAINHENT AIR LOCK which includes both doors, as well as the interlock mechanism and the leak-tightness of the barrel. ACTIONS are provided (proposed ACTIONS A and B) to ensure that if one door or its interlock mechanism is inoperable, the other door is closed, locked and periodically verified to be closed and locked. If the interlock mechanism is inoperable, an allowance is provided to open the door provided a dedicated individual controls the access. Notes are provided to allow, the locked closed

'verification to be performed administratively if the door is in a limited access area. These two new actions are not applicable, however, if the entire air lock is inoperable (as stated in proposed Note 1 to both ACTIONS A and B). To ensure that the primary containment LCO will be entered if air lock leakage results in exceeding overall primary containment leakage, NOTE 2 to the ACTIONS is also included. Overall, these new ACTIONS provide additional restrictions to plant operation.

CTS 4.7.A.2.h requires repairs to be initiated immediately when it is determined that the criterion of 4.7.A.2.g is exceeded and if conformance to these criterion is not demonstrated within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> following detection of excessive local leakage, a reactor shutdown is required. ACTION C of the proposed Specification requires the licensee to initiate action to evaluate primary containment overall leakage rate using the current air lock test results immediately, verify an air lock door closed within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and restore the air lock to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If required ACTION C and the associate Completion Time is not met, the unit must be in HODE 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and HODE 4 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This is more restrictive than current requirements.

This change adds a Surveillance to verify the interlock mechanism works properly (only one door can be opened at a time). This will ensure that one door is always closed which maintains containment integrity. The addition of new requirements represents a more restrictive change.

The current requirements for the air lock are located within the primary containment TS requirements (CTS 3.7.A.2.a), which requires the primary containment to be OPERABLE at all times when the reactor is critical or when the reactor water temperature is above 212'F and fuel is in the vessel. The proposed BFN ISTS 3.6.1.2 applicability is HODES 1, 2, and 3. This is more restrictive since CTS does not require the primary containment to be OPERABLE when in HODE 2, not critical, and < 212'F.

BFN-UNITS 1, 2, & 3 Revision 0 P@GF g QF

UNIT 3 CURRENT TECHNICAL SP ECIF ICATION MARKUP

4.7.A. a Co a 2oae Primary containment 2. te ated Leak Rat est integrity shall be m> Z.< l 3 maintained at all times Primary containment nitrogen vhen thc reactor is critical consumption shall be R pp)scab'>I i or vhcn the reactor vater monitored to determine the temperature is above 212 F average daily nitrogen and fuel ie in thc reactor consumption for thc last veeec 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Excessive leakage ing "open vessel" ie indicated by a 82 physics tests at pover consumption rate of > 2X of levels not to exceed the primary containment free 5 HW(t). volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrected for drywell

b. Primary containment tcmperaturc, pressure, and integrity ie the maximum confirmed allovablc if venting operations) at 49.6 peig. Corrected to integrated leakage rate, normal dryvcll operating La, does not exceed the pressure of 1.1 psigf this equivalent of 2 percent of the primary containment value is 542'SCFH. If this value is exceeded, the volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the action specified in 49.6 psig design basis 3.7.A.2.C shall be taken.

accident pressure, Pa.

Perform leakage rate testing C~ If E2 makeup to the primary in accordance with thc Primary containment averaged over Containmcnt Leakage Rate 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrected for Testing Program.

pressure, temperature, and venting operations) exceeds 542 SCFH, it must be rcduccd 5<< WuSW Fs'cation Q<

to < 542 SCFH within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> BC'Sf'5 Q,Q>9'c 3,g, ~,(

or the reactor shall be placed in Hot Shutdown within the next 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.

BFH 3.7/4.7-3 aMreMmr NO. 228 .

Unit 1 PAGE~OF

Cl

~,

4. 7.A. 2. (Cont 'd)

Zf at any time it is determined that the criterion of 4.7.A.2,g is exceeded, repairs shall be initiated immediately.

(2) Zf conformance to the criterion of

+~'e +~kÃi~4it 'Gr 6 Aptly 4.7.A.2.g is not 4~ gf'N IsrS g.g/.Iyg~ ( p demonstrated within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> following detection of excessive local leakage, the reactor shall be shut down and depressurixed until repairs are effected and the local leakage meets the acceptance criterion as demonstrated by retest.

sg s.6./.3. /o tK isolation valves shall be tested at a pressure of 25 psi for leakage durin ach refuels.n p2. outa e t Zf e leakage rate of 1l.5 scf/hr for any one main steamline isolation valve is exceeded, repairs and retest shall be performed to correct the condition.

BFN 3.7/4.7-8 Unit 1

3.7.C 3- Secondary containmcnt integ-rity shall be maintained in the refueling xone, except as specified in 3.7.C.4.

4. If refueling zone secondary containment cannot bc maintained the following conditions shall be mct:

a. Handling of spent fuel and all operations over spent fuel pools and open reactor

~elis containing fuel shall be prohibited.

b. The standby gas treatment system suction to thc refueling zone vill be blocked ~cept for a controlled leakage area sized to assure the achieving of a vacuum of at least 1/4-inch of water and not over 3 inches of

~ater in all three reactor ey.cgt e Keac~c Suig g zones. This is only appli- lfd culm br<ag~g cablc if reactor xone integrity is required.

Mhen Primary Containment 1. The primary containment Integrity is required, all isolation valves rimary containment isolati surveillance s6all bc valves and all reactor performed as follows:

coolant system instrument

~36./.3 line floe check valves s 11 a. At least once r o cr-bc OPERhB except as ating c clc the OPER-specified in 3.7.D.2. primary contain-ment isolation valves

• Locked or sea cd closed valves that are po~er operated may be opened on an inter- ~< 3,e. l,3. 5 and automatically mittent basis under CR p.g,!,~. to initiated shall be administrative control. SP. g,v, l. 3.1 tested forinitiation simulated automatic Ac os.

Ll SFN 3.7/4.7-17 SlegMNr N0. y 8 g Unit 1

MckEI~

Qai SR 3.i .1.3.5 az,c,.l z d ia accordance vith Specification lo0ol%lg tested for closure times.

b. In accordance with f< 8'M HC1(op) 8 Specification 1.0.%5, all normally open povcr operated t'r.e4ug 8<T>oz p primary containment isolation valves shall bc (Q r sid kCr i~) F fuactionally tested.

C~ (Deleted) f~~ s~4 AJ4~ onl5 ~<3.4.1.'3 Sindhi d

t At leas once pcr 1<4 used ALIAS 3+9 H Q.TiOWX EF'CV ac operatin c cl the l4 Bc iSo)pHo OP ILITY of the PsiW~o n reactor coolant system tah J instrument line floe i tlstvu~g+ /q check valves shall be Wcc t signai verified.

2. Ia the even any primary 20 Mhenever a primary

! c tai olation valve contaiamcnt isolation valve becomes inoperable, reactor <<Owu<A is inoperable, thc position operation may continue provided ItC Tip P r 4t.'o~

of at least the at least valve, ia each line valv each line having an

~

l~nl'how oae having an inoperable valve, is ino rable valve shall be QTlo OPERhBLE and s ecor e daily eithers Lq PyG

a. The inoperablc valve is l(rtosedPs P,t,l, Z. )

restored to OPERABLE 3o 0 el i3.Z status, or l.3.'3

3. 4 ~

b. Each affected line is 3as ol

. isolated by use of at least g,s,, ls 3,g RC7(od one deactivated contaiameat isolation valve secured ia the isolated position.

<loSed mang~l Valve> gl;+

3. If Specification 3.7.D.l and

~l~<~ o<<hect Vole W4~

3 7.D.2 cannot be mct, aa orderly shutdcnm shall be Cl~ 4h~~gh <he Valge Sec~rg

~<<4" initiated and the reactor shall g bc ia th COLD SHUTDOWN CONDITION

+it hour's ~

L3 3.7/4.7-18 Spà Unit 1 He HoTSNutnowu NENOMHfT N5. f8 9 C~on->o~ <n iZ

+~vs @gal.iA i ACi "~C-

5ftC <4<rabO 3. t.. l.3 FEB 13 19%

3.7.F. 4.7.F.

. The primary containment purge l. At least once every 18 system shall be OPERABLE for months, the pressure drop PURGIHG, except as specified across the combined HEPA in 3.7.F.2. filters and charcoal adsorbcr banks shall be

a. The results of the ia-place demonstrated to be less cold DOP and hslogenatcd than 8.5 inches of vater hydrocarbon tests at design at system design flow flovs on HEPA filters and rate {g 10%).

charcoal adsorber banks shall shov g 99K DOP removal a. The tests and sample and g 99K halogcnated hydro- analysis of Specifica-carbon removal vhen tested tion 3.7.F.1 shall be in accordance vith performed at least once AHSI H510-1975. per operatiag cycle or once every 18 months,

b. The results of laboratory vhichever occurs first carbon sample analysis shall or after 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of shov g 85K radioactive system operation and methyl iodide removal vhca following significant tested ia accordance vith painting, fire, or ASTN D3803. chemical release in any ventilation zone commmicating vith the

c. System flov rate shall bc systcao shown to be vithin g lOX of design flov vhea tested b. Cold DOP testing shall ia accordance with be performed after each ASSI H510-1975 complete or partial replacement of the HEP

2. If the provisions of 3.7.F.l.a, filter bink or after b, and c cannot be aet, the any structural mainte-system shall be declared nance on the system iaoyerable. The provisions of housing.

Technical Spccificatioa 1.C.l

'e do aot apply. PURCIHC aay coa- c. Halogenatcd hydrocarboa thrns using the Staadby Qas testing shall be Treatment Systea performed after each complete or partial ao The 18-inch primary contain- reylacement of the acnt isolation valves asso- charcoal adsorber bank ciated vith PURQIHC may be or after any structural open during the RUN mode aaintenancc on the for a 24-hour period after system housing.

enteriag the RUN aodc aad/or for a 24-hour period prior S<.'e 5<bagl~Hon Q Qgg< g to entering the SHUTDOWH 4'r Cy5 37 F/q<7~F ln t.h4'c<hon g, (, ].3 APA 29 tg9t these primary

~'~'i'~ containment fsolation valves is governed by Technical Specification 3.7.D.

b. Pressure control of the cont nment i norma ly perfo ed by IHQ Z.A (

through 2-fnch rfmary ontainm t isol tion ives vh ch rout ef luent t the St dby Gas reatmen System.

The EIUNILI o f these rimary contaf ent iso tion valves i governe by Technical pecification 3.7.D.

3.7.G.

1. The Containment Atmosphere Dilution (CiD) System shall be OPERABLE vith:

a.

torus'.

Tvo independent systems capable supplying nftrogen to the dryvell and of Cycle each solenoid operated air/nitrogen valve through at least one complete cycle of fn full travel accordance vfth Specification 1.0.MK, and at least once per month verify that each manual valve fn the flov path is open.

b. A minimum supply of b. Veri that the CAD 2,500 gallons of System contains a lfqafd nitrogen per minimum supply of systems 2,500 gallons of lfgafd nitrogen tvic

<<St'. t-I C+O~ Q( er veek.

C~ 4<4" BPS .7/4.7-22 ENDMae NtL Z se th6t 1 PAGE~OF~

INSERT PROPOSED NEW SPECIFICATION 3.6.1.4 Insert new Specification 3.6.1.4, "Drywell Air Temperature," as shown in the BFH Unit 2 Improved Standard Technical Specifications.

0 JUSTIFICATION FOR CHANGES BFN ISTS: 3.6.1.4 - DRYMELL AIR TEHPERATURE TECHNICAL CHANGES - NORE RESTRICTIVE Hl A new Specification is being added requiring drywell air temperature to be 150'F. This is required since some accident analyses assum'e this temperature at the start of an accident. Appropriate ACTIONS and Surveillance Requirements are also added. This is consistent .with the BWR Standard Technical Specifications, NUREG 1433.

0 BFN-UNITS 1, 2, 8L 3 Revision 0

.u

0 UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP PAGE OF

5'eCe.hCa Ond b f Al 4 7 A. a Co 2 's Primary containment 2. e ae integrity shall be LCo 3.a. l.3 maintained at all times Primary containment nitrogen PPPli Cab t e vhen the reactor is critical consumption shall bc or. vhen the reactor vater

~

monitored to determine the temperature is above 212 F average daily'nitrogen and fue s in the reacto consumption for thc last esse ccpt w c 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Excessive leakage performing "open vessel" is indicated by a H2 physics tests at power consumption rate of > 2X of levels not to exceed the primary contaiamcnt free 5 Kf(t). volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrcctcd for dryvell

b. Primary containment temperature, pressure, and iategrity is confirmed the maximum allovable if venting operations) at 49.6 psig. Corrected to integrated leakage rate, normal dryvell operating La, does not exceed the prcssure of 1.1 psig, this equivalent of 2 percent of value is 542 SCFH. If this thc primary containment value is exceeded, the volume pcr 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the action specified ia 49.6 psig design basis 3.7.h.2.C shall be taken.

accident pressure, Pa.

Perform leakage rate testing C~ If 52 makeup to the primary ia accordance vith thc Primary containment averaged over Containmeat Leakage Rate 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrcctcd for Tcstiag Program.

pressure, temperatures aad venting operations) exceeds 542 SCFH, it must bc reduced 5ee &~we'eeei n CeeChuys to < 542 SCFH vithin 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or the reactor shall be p BF< isis 3 r.i.l 0

placed in Hot Shutdown

~

within the next 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.

hMENStEÃf NL 243 BPS 3.7/4.7-3 Unit 2 FAGE~OF 7

+ ciCAfiow s.C./.3 4.7.A.

4.7.A.2. (Cont'd)

(1) If at any time it determined that the is criterion of 4.7.A.2.g is exceeded, repairs shall be initiated immediately.

(2) If conformance to the

~c >$ 446$ io~ p criterion of C %~5'~ gfh/ 4.7.A.2.g is not IS7S 3.6.I./ +3.C./.2. demonstrated within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> following detection of excessive local leakage, the reactor shall be shut down and depressurized until repairs are effected and the local leakage meets the acceptance criterion as demonstrated by retest.

3. C. /.'R The main steamlxne isolation valves shall be tested at a pressure of 25 psig for leakage during eac re ue x If the leakage rate of 11.5 scf/hr for any one main steamline isolation valve is exceeded, repairs and retest shall be performed to correct the condition.

BFN 3.7/4.7-8 Unit 2 PAGE

3.7,C, Se o d Co ta ent

3. Secondary containment integ-rity shall be maintained in qgP VASTlAJAR'iON FOR the refueling zone, except as gpwN~s Fog ZHiv ad 3.6.V./

specified in 3.7.C.4.

4. If refueling zone secondary containment cannot be maintained the folloving conditions shall be met:

a. Handling of spent fuel and all operations over spent fuel pools and open reactor wells containing fuel shall be prohibited.

b. The standby gas treatment system suction to the refueling zone vill be blocked except for a controlled leakage area sized to assure the achieving of a vacuum of at least 1/4-inch of vater and not over 3 inches of eater in all three reactor ms+ paa J r 'll. l, 1b zones. This is only appli- r(

cable if reactor zone QC,(aalesara Qrteakg integrity is re uired.

ima e oato ma tai t Isol on V V e

~

. l. Shen Primary Containment 1. The primary containment g~li~ob. IA Integrity is required, all isolation valves rimary containment isolation surveillance shall be valves and all reactor performed as follows:

coolant system instrumen Q~

LC.O 3. lo./, 3 line flow check valves shall a. At least once per o er-be OPERAB except as ti c c the OPER-specified in 3.7.D.2. ABLE primary contain-ment isolation valves

• Locked or sealed closed valves that are pover operated may be opened on an intermittent sR 3.4.1.3.5 and automatically basis under administrative control. SR ~4.I.M initiated shall be SR3.l'm. 1.3.7 tested for imulated go+ ( ~ +CTIONg automatic initiation

<gag ko SR. 3.C.t ) act+ad. or I BFH 3.7/4.7-17 NENOMEgr go. 20g Unit 2 PAGE t OF I

'

at Vaa'yes sR 3.g,/,3p SR ~ C.(.3. and in accordance with g

Specification 1.0.MM, tested for closure times.

In accordance with Specification 1.0.MN, all normally open power L5 P~P ~ AC7.(oe 8 operated primary containment isolation valves shall be Propos 4'o6l D functionally tested.

PmposM hcT(oQ p c. (Deleted)

Sg 3.C.l.8.8

d. At least nce pe

/6 ~"o ~c'4 No>4. 2 4a ACAahP o erati 'c c the tFCV w+Q Propos~ (" cs g l 4ci c7cogg 4 ~

p4S>)i~

iso/aA'm o>f OPERABILITY of the reactor coolant system s:~/~~ instrument line flow 2~ In the event any pr mary conta n

/l~C S) vo

$ ~

lh jfrlf~<g 2.

check valves shall be verified.

enever a primary contain-ent o va v becomes ment isolation valve is inoperable, reactor operation may ~A/4<<cg inoperable, the osition of continue provided at least one Ack~

CoA ki t least one other valve in Ae c.

valve, in each line having an 4.Z+C,2. each line having an inoperable valve, is OPERABLE ino erable valve shall be and thin 4 hours either: recor e ail A('TlOhLS LY P,e+ a. The inoperable valve is restored to OPERABLE ~roPoL~ Sls 3 Co. I 3 status, or 3.C, L3.2

b. Each affected line is S.C.J 3. 3 gcyuirQ isolated by use of at least 3.4 /2. g Aa4ia~ . one deactivated containment Z.C. ( P. g R. I +C. [ isolation valve secured in the isolated positio mc wag w~ Ip4 f,/;g

3. If Specification 3.7.D.1 and "k i o~ +Ice(c. vg/

3.7.D.2 cannot AC.<lou be met, an orderly shutdown shall be initiated and the reactor shall P/~ + J ~ lr~/~ Secor~

E, be i t COLD SHUTDOWN COHDITIOH within ours.

3&

BFH

~'+ La 3.7/4.7-18 AMENDMEHT NO 204 Unit 2 Pl 8 ggacVlA~~

~ogo iTic 5 o;,V (2 lip,~

~ 7.F. o t 4.7.F. 0

~Ss~te

1. Thc primary containment purge 1. At least once every 18 system shall be OPERABLE for months, the prcssure drop PURGIHG, except as specified across the combined HEPA in 3..7.F.2. filters and charcoal adsorber banks shall be

a. The results of the in-place demonstrated to be less cold DOP and halogenated than 8.5 inches of vater hydrocarbon tests at design at system design flov flows on HEPA filters and rate (g lOX).

charcoal adsorber banks shall show g 99K DOP removal a. The tests and sample and g 99K halogenated hydro- analysis of Specifica-carbon removal vhen tested tion 3.7.F.1 shall be in accordance vith performed at least once AHSI H510-1975. per operating cycle or once every 18 months,

b. The results of laboratory vhichever occurs first carbon sample analysis shall .or after 720 hoars of shov g 85K, radioactive system operation and methyl iodide removal vhcn folloving significant tested in accordance vith painting, fire, or ASTI D3803. chemical release in any ventilation xone communicating vith thc

c. System flov rate shall be systems shown to be vithin g 1OX of design flov vhcn tested b. Cold DOP testing shall in accordance vith be performed after each AHSI H510-1975 ~ complete or partial replacement of the HEPA

2. If the provisions of 3.7.F.l.a, ~

filter bank or after b, and c cannot be met, the any structural maintc system shall be declared nance on the system inoperable. The provisions of housing.

Technical Specification 1.C.l do not apply. PURGIHG may con- c. Halogeaatcd hydrocarbon tixxae using the Standby Gas testing shall be Treatment System. performed after each complete or partial 3o ae The 18-inch primary contain- replacement of the ment isolation valves asso- charcoal adsorber bank SR s.< 1.3. I ciated vith PURGIHG may be or after any structural f4of~ open during the RUH mode maintenance on the for a 24-hour period after system housing.

entering the RUN mode and/or for a 24-hour period.

to eater prior the SHUTDOMN SEE &$TI Pic'&ion)

F~~ c~S g 7~/q fog <<""- 5$

mode. e 0 TY of Sec4io ~

BPK Unit 2-

~-'~-> " .... 3.7/4.7-21 NENMRf NO 231

APR 2 9 1991

~ s. a e these primary

/Co 9.C.t. 3 containment isolation valves is governed by Technical Specification 3.7.D.

b. Pressure control of the contai nt is normally performed by VENTING through 2- ch primary containment olation valves vhich ute ffluent to the Standby G Treatment Sy em.

The PERABILITY o these rimary contai ent isolatio valves governed by Technical ecification 3;7.D.

3.7.G. Co ta e mos ere 4.7.G. Co ta e t t os ere ut o S ste C utio S stem C D

1. The Containment Atmosphere 1. S st 0 crab t Dilution (CAD) System shall be OPERABLE vith:

a. Tvo independent a. Cycle each solenoid systems capable of operated air/nitrogen supplying nitrogen valve through at to the dryvell and least one complete torus. cycle of full travel in accordance vith Specification 1.0.MM, and at least once per month verify that each manual valve in the flov path is open.

b. A minimum supply of b. Verify that the CAD 2,500 gallons of System contains a liquid nitrogen per minimum supply of system. 2,500 gallons of liquid nitrogen tvice per veek.

~ ..

Unit 2 5 E~ 0 <S TI F' C AT t o g F'o~

.7/4.7-22 AMENDMEMTN0. I9 C9+n'~ Fag. Pp/J <<~ Z.g.g,i ~

7'AG~~o~~

0' INSERT PROPOSED NEW SPECIFICATION 3.6.1.4 Insert new Specification 3.6. 1.4, "Drywell Air Temperature," as shown-in the BFN Unit 2 Improved Standard Technical Specifications.

JUSTIFICATION FOR CHANGES BFN ISTS: 3.6.1.4 - DRYWELL AIR TEMPERATURE TECHNICAL CHANGES - NORE RESTRICTIVE Hl A new Specification is being added requiring drywell air temperature to be 150'F. This is required since some accident analyses assume this temperature at the start of an accident. Appropriate ACTIONS and Surveillance Requirements are also added. This is consistent .with the BWR Standard Technical Specifications, NUREG 1433.

BFN-UNITS 1, 2, 5, 3 Revision 0

UNIT 3 CURRENT TECHNICAL SPECIFICATION

2oae Primary containment 2. te rat d e ate est integrity shall be maintained at all times Primary containment nitrogen when the reactor is critical consumption shall be

+l >CA bo l e'fy or when the reactor water monitored to determine the t'emperature is above 212 F average daily. nitrogen and fuel is in the reactor consumption for the last vessel e 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Excessive leakage ing "open vessel" is indicated by a H2 physics tests at power consumption rate of > 2X of levels not to exceed the primary containment free 5 MW(t). volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrected for drywall

b. Primary containment temperature, pressure, and integrity is confirmed the maximum allowable if venting operations) at 49.6 psig. Corrected to integrated leakage rate, normal drywell operating La, does not exceed the pressure of 1.1 psig, this equivalent of 2 percent of value is 542 SCFH. If this the primary containment value is exceeded, the volume per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the action specified in 49.6 psig design basis 3.7.k.2.c shall be taken.

accident pressure, Pa.

Perform leakage rate testing co If H2 makeup to the primary in accordance with the Prima containment averaged over Containment Leakage Rate 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrected for Testing Program.

pressure, temperature, and venting operations) exceeds 542 SCFH, it must be reduced e g~hknlfio~ kR Qagr5 to < 542 SCFH within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> foA BFQ [5+5 g,4g,/

or the reactor shall be placed in Hot Shutdown within the next 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.

BFK 3.7/4.7-3 NENMERr go. 2 Og Unit 3 ma~ ~

4.7.A.

4.7.A.2. (Cont'd)

h. (1) Zf at any time it is determined that the criterion of 4.7.A.2.g is exceeded, repairs shall be initiated immediately.

(2) Zf conformance to the criterion of 4.7.A.2.g is not

~<~ +~$ 5~~4%40~ 4" C(~~ demonstrated within Ar it/-nl /st y.g,/.I ~~~ I + 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> following detection of excessive local leakage, the reactor shall be shut down and depressurized until repairs are effected and the local leakage meets the acceptance criterion as demonstrated by retest.

SR Z.C./3.~o main steamline isolation valves shall be tested at a pressure of 25 psig for leakage during each refuelzn outa e Zf the leakage rate of 11. 5 scf /hr for any one main steamline isolation valve is exceeded, repairs and retest shall be performed to correct the condition.

BFN 3.7/4.7-8 Unit 3

0 3.7.C

3. 5ccondary contaiameat integ-rity shall bc maintained in cc wushCi'ccgi~

the rcfueliag zone, except as specified in 3.7.C.4. Ch~ ~, 8c'N isfs w.~.q,j

4. Ig refueliag zone secondary containment cannot be maintained the folloving conditions shall bc met:

a. Handliag of spent fuel and all operations over spent fuel pools and open reactor vclls coataining fuel shall bc prohibited.

The standby gas treatment system suction to the refucliag xone vill bc blocked except for a controlled leakage area sized to assure the achieviag of a vacuum of at least 1/4-inch of vater aad not over 3 inches of vater in all three reactor epee~ geaH+v zones. This is only appli- pcgguW +<at'c< S cable if reactor zone integrity is required.

D D.

liCalsth

l. Mxen Primary Containment 1. The primary containment Integrity is required, all isolation valves primary contaiament surveillance shall bc isolation valves and all performed as follovs: P2.

reactor coolant system Lco kc,ty inst t line flov check valves shall be OPERAB ao it least once per o cr-atiag cycle, e OPER-czcept as specified ia ry contain-3.7.D.2 ment isolation valves that are pover operated

• Locked or scaled closed valve SR ~.6.t.ws and automatically may be opened on an intermittent gag.&.L3. 0 initiated shall be basis under administrative control tested for simulated Pfo~ l +e ~Ti'ow5 sR 3.r .l.s.7 automatic initiation sg s,g,(,3,g OD OR Lt BHl 3.7/4.7-17 tiait 3 NENOMENf Ntt. 16L

5 ec;Simeon K4 ~ l 3 NV 18 592 gl and in accordance vith Specification 1.0.$ t, tested for closure times.

b. In accordance vith 45 Specification 1.0.MN, ro emn g all normally open pover L ~ seA HcHo~ operated primary containment isolation Filo/><<A pcVion F valves shall tested be'unctionally PapoScd Noh W 4 Rch'on5 c. (Deleted) 5 Z

d. At least once per

~ oP<Srd N&S 3+/ +AonS operating cycl the ECe4 a Ww oPB o the fo %t <5ol atia& reactor coolant system fes:how on a instrument linc flov check valves shall be linc ggav.

verified S

ignis

2. In the even primary contain 2. whenever a primary contain-ent isolation valv ccomes ment isolation valve is o c, reactor operation may inoperable, the position of continue provided at least one %H n at least one valv in eoAcii lion valve, in each line having an 4,+C each line having an A+e. inoperablc valve, is OPERABLE ino erablc valve shall be and our either: ordcd da y.

P cnuz A+~ The inoperable valve is restored to OPBRABLB f Oops'tl SRs status, or 3

~ 4.I.S.3 b Each affected linc is 3'o c,l,g,g EcQa6rclk isolated by use of at least .l.3.$

4@+ n g,l+ one deactivated containment L3 4al isolation valve secured the isolated position. <losed ~n~) Value,gl;nd t 3. If Specificationbc 3.7.D.lan and ~<a%<,~ caw.i va>n ~,~

3.7.D.2 cannot mct, ohe vaNe gecur~ot orderly shutdovn shall bc initiated and the reactor shall G bc th COLD SHUTDOWN( COHDITIOK vi hours'i BPK AT >Halo~

3.7/4. 7-18 AMENDMENT NO. I6 y Unit 3 < Coa)Dido& LR AI

~s 4& l~ PAGE

Q'e cia'I ~ 3 FEB 1 81995

.7.F. t c 4.7.F.

~Ssteg

1. The primary containment purge l. At least once every 18 system shall be OPERABLE for months, the pressure drop PURGIHG, except as specified across the combined HEPA in 3.7.F.2. filters and charcoal adsorbcr banks shall bc

a. The results of thc in-place demonstrated to bc less cold DOP and halogenated than 8.5 inches of vater hydrocarbon tests at design at system design flov flovs on HEPA filters and rate (g 10Z).

charcoal adsorber banks.

shall shov g 99Z DOP removal a. The tests and sample and g 99Z halogenated hydro- analysis of Specifica-carbon removal vhcn tested tion 3.7.F.1 shall be in accordance vith performed at least once AHSI H510-1975. per operating cycle or once every 18 months,

b. The results of laboratory vhichever occurs first carbon sample analysis shall or after 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of shov g 85Z radioactive system operation and methyl iodide removal vhcn folloving significant tested in accordance vith painting, fire, or k AS'3803 ~ chemical rcleasc in azar ventilation zone communicating vith thc

c. System flov rate shall bc system.

shovn to be vithin g 10Z of design flov vhcn tcstcd ~

b. Cold DOP testing shall in accordance vith bc performed after ea AHSI H510-1975 ~ complete or partial replacement of the HEPA

2. If the provisions of 3.7.F.l.a, filter bank or after b, and c cannot be met, thc any structural mainte-systea shall be declared nance on thc system inoperable. The provisions of housing.

Technical Specification 1.C.1 do not apply. PURCIHC may con- c. Halogenated bydrocarbon tinue using th>> Standby Cas testing shall be Treatment System. performed after each Section complctc or partial 3o ao The 18-inch primary contain- replacement of the aent isolation valves asso- charcoal adsorbcr bank SC p,r,~,p,I ciated vith PURGIHG may be or after axe structura gobe, open during the RUH mode aaintcnance on the for a'4-hour period after stem housing.

entering the RUH mode and/or St:e <icsAfrczgc,n Q. C+g~

for a 24-hour period prior ~~/> >1 to entering the SHUTDOWH </V VFin P.kj) mode. e OPERABILITX of BFI Lco F,y.[,y 3.7/4.7-21 AMENDMENT NO. I S 8 Unit 3

5(ec.i Ac~+on 3,4 ~ ( 3 2 9 1991 3.7.F.

these primary containment isolation valves is governed by Technical Specification 3.7.D.

b. Pressure ontrol of thc ontainmcn is normally p rformed b VEHTIHG th ough 2-in primary con ainment is ation valv s vhich ro e efflu t to the andby Gas Tr tment Sys The OPE ILIA of thcsc pr ry containm isolation valves is vcrned by Tcchnical Specification 3.7.D, 3.7.G. 4.7.G.

The Containment Atmosphcrc Dilation (CAD) Systea shall be OPERABLE vith;

a. Two independent a. Cycle each solenoid systems capable of operated air/nitrogen supplying nitrogen valve through at to the dryvell and least onc complete torus>> cycle of full travel in accordance vith Specification 1.0.MM, and at least once per month verify that each manual valve in thc flov path is open.

b. A miniama supply of b. Verify that thc CAD 2,SOO gallons of Systea contains a liquid nitrogen pcr minimum supply of system>> 2,500 gallons of liquid nitrogen tvici

~'~ ~~Auto~ ro, gp cs cr vc ck

~

&It gpN ($ y BFI ~ 7/4.7-22 SWIDNrryy, g gs Unit 3

INSERT PROPOSED NEW SPECIFICATION 3.6.1.4 Insert new Specification 3.6. 1.4, "Drywell Air Temperature," as shown in the BFN Unit 2 Improved Standard Technical Specifications.

0' JUSTIFICATION FOR CHANGES BFN ISTS: 3.6.1.4 - DRYWELL AIR TEMPERATURE TECHNICAL CHANGES - NORE RESTRICTIVE Hl A new Specification is being added requiring drywel1 air temperature to be 150'F. This is required since some accident analyses assume this temperature at the start of an accident. Appropriate ACTIONS and Surveillance Requirements are also added. This is consistent with the BWR Standard Technical Specifications, NUREG 1433.

BFN-UNITS I, 2, 5 3 Revision. 0 PAGE

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.3 -,. PRINRY CONTAINNENT ISOLATION VALVES ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance'ith the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

In addition, the PCIV LCO now exempts the reactor building-to-suppression chamber vacuum breakers and scram discharge volume vent and drain valves since they are governed by other LCOs. Any changes to the requirements for these valves are discussed in the new LCO Justification for Changes.

A2 The current technical specification (CTS) 4.7.D.l.a frequency of "once per operating cycle" has been changed to "In accordance with the Inservice Testing Program" for proposed SR 3.6.1.3.5 (stroke time tests). The CTS 4.7.D.l.d frequency of "once per operating cycle" has been changed to "18 months" for proposed SR 3.6. 1.3.8. Since an operating cycle is 18 months and the current IST program requires testing every 18 months, this change is considered administrative in nature. The CTS 4.7:A.2.i frequency of "each refueling outage" has been replaced with "in accordance with the Primary Containment Leakage Rate Testing Program" for SR 3.6. 1.3.10. This program requires Appendix J requirements to be met. The Appendix J requirements will always supersede the Technical Specification requirements (unless an exemption is approved) since Appendix J is the rule. Therefore, this change is purely an administrative preference in presentation.

A3 This proposed Note ("Separate Condition entry is allowed for each penetration flow path") provides explicit instructions for proper application of the actions for Technical Specification compliance. In BFN-UNITS 1, 2, & 3 Revision 0

JUSTIfICATION FOR CHANGES BFN ISTS 3.6.1.3 - PRIMARY CONTAINMENT ISOLATION VALVES conjunction with the proposed Specification 1.3 - "Completion Times,"

this Note provides direction consistent with the intent of the existing Actions for inoperable isolation valves.

A4 The proposed ACTIONS include Notes 3 and 4. These Notes facilitate the use and understanding of the intent to consider any system affected by inoperable isolation valves, which is to have its ACTIONS also apply if it is determined to be inoperable. Note 4 clarifies that these "systems" include the primary containment. With proposed LCO 3.0.6, this intent would not necessarily apply. This clarification is consistent with the intent and interpretation of the existing Technical Specifications, and is therefore considered an administrative presentation preference.

AS The current single Action for "any primary containment isolation valve" has been divided into three ACTIONS. Proposed ACTION A for one valve inoperable in a penetration that has two valves, proposed ACTION B for two valves inoperable in a penetration that has two valves, and proposed ACTION C for one valve inoperable in a penetration that has only one valve. All technical changes are discussed elsewhere in this section.

As such, this change is considered an administrative presentation preference.

TECHNICAL CHANGES - MORE RESTRICTIVE Ml CTS 3.7.D.3 requires an orderly shutdown be initiated and the reactor to be in the COLD SHUTDOWN CONDITION within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when certain conditions can not be met. Proposed Action E will require the plant be in MODE 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The addition of this intermediate step to the COLD SHUTDOWN CONDITION is considered more restrictive since CTS does not require any action to have taken place within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. 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 safety systems.

M2 CTS applicability for PCIV operability is when primary containment integrity is required. Per CTS 3.7.A.2.a, primary containment integrity is required at all times the reactor is critical or when the reactor water temperature is > 212'F and fuel is in the reactor vessel. The proposed applicability of MODES 1, 2, and 3 is more restrictive since CTS does not require primary containment integrity when in NODE 2, not BFN-UNITS 1, 2, 8E 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.3 - PRIMARY CONTAINMENT ISOLATION VALVES 0

critical and ( 212'F. The proposed Specification is also applicable when associated instrumentation is required to be OPERABLE per LCO 3.3.6. 1, which adds a MODE 4 and 5 requirement for the RHR Shutdown Cooling isolation valves. An appropriate ACTION has been added (proposed ACTION F) for when the valves cannot be isolated (since the unit is already in MODE 4 or 5, the current actions provide no appropriate compensatory measures). ACTION F requires the licensee to initiate action to suspend operations with the potential for draining the reactor vessel immediately and to restore valve(s) to OPERABLE status immediately. If suspending an OPDRV would result in closing the RHR Shutdown Cooling valves, an alternative required action is provided to immediately initiate action to restore the valves to OPERABLE status.

M3 New Surveillance Requirements have been added. SRs 3.6. 1.3. 1, 3.6. 1.3.2 and 3.6. 1.3.3 ensure PCIVs are in their proper position or state. SRs 3.6. 1.3.4 and 3.6. 1.3.9 ensure the traversing incore probe (TIP) squib valves will actuate if required. These SRs are additional restrictions on plant operation.

This change adds acceptance criteria to the Surveillance requires an Operability test of the instrument line excess flow Requirement'hich check valves (EFCVs). The acceptance criteria added requires that the EFCVs actuate to the isolation position on a simulated instrument line break signal. The addition of acceptance criteria which did not previously exist in Technical Specifications constitutes a more restrictive change.

TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" .

LA1 CTS 3.7.F.3.b provides no requirements, it just explains that the normal method of containment pressure control is through 2-inch PCIVs, which route effluent through the SGTS. Since the OPERABILITY of these valves is governed by proposed BFN ISTS 3.6. 1.3, the specification provides no requirements and has been eliminated. Any details relating to PCIV operability have been relocated to the Bases of LCO 3.6. 1.3. Placing these details in the Bases provides assurance they will be appropriately maintained since changes to these details will require a 50.59 evaluation.

BFN-UNITS 1, 2, & 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.3 - PRIMARY CONTAINMENT ISOLATION VALVES "Specific" Ll The phrase "actual or" in reference to the automatic isolation signal, has been added to the Surveillance Requirement for verifying that each PCIV actuates on an automatic isolation signal. Thi's allows satisfactory automatic PCIV isolations for other than Surveillance purposes to be used to fulfill the Surveillance Requirements.

Operability is adequately demonstrated in either case since the PCIV cannot discriminate between "actual" or "simulated".

L2 The provisions of the "*" Note of CTS 3.7.D. 1 are encompassed by Note 1 to the ACTIONS, which allows penetration flow paths to be unisolated intermittently under administrative controls (except for the 18-inch purge valve penetration flow paths). However, the ISTS allowance applies to all primary containment isolation valves (except for 18-inch purge valve penetration flow paths) not just locked or sealed closed valves. The allowance is presented in proposed ACTIONS Note 1 and in SR 3.6. 1.3.2, Note 2. Opening of primary containment penetrations on an intermittent basis is required for performing surveillances, repairs, routine evolutions, etc.

CTS 3.7.D.2.b allows isolating the primary containment penetrations with at least one deactivated valve secured in the isolated position when one PCIV is inoperable. The proposed ACTIONS A and C of LCO 3.6. 1.3 allow the use of at least one closed and de-activated automatic valve, closed manual valve, blind flange, or check valve (for Condition A only) with flow through the valve secured. The Action utilizing a deactivated automatic or manual valve is appropriate on the basis that these isolations present a boundary which is not affected by a single failure.

The ability to utilize the valves downstream of the outboard PCIVs is an acceptable isolation since it meets the acceptance criteria of not being affected by a single active failure.

L4 CTS 3.7.D.2 allows reactor operation to continue when any PCIV becomes inoperable provided that at least one valve in each line having an inoperable valve is operable and within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> the affected line is isolated or the inoperable valve is restored to OPERABLE status. Based on the wording, this only applies to lines with two isolation valves.

This is equivalent to proposed ACTION A, however, the proposed ACTION allows additional time to isolate the main steam lines. A Completion Time of 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> s for the MSLs allows a period of time to restore the MSIVs to OPERABLE status given the fact that MSIV closure will result in isolation of the MSLs and a potential for plant shutdown. For BFN-UNITS 1, 2, 8L 3 Revision 0

0 JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.3 - PRINRY CONTAINMENT ISOLATION VALVES penetration flow paths with only one PCIV, proposed ACTION C allows 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to restore an inoperable valve to OPERABLE status and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to restore EFCVs in reactor instrumentation line penetrations. The four hour Completion Time is reasonable considering the relative stability of the closed system to act as a penetration boundary and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. The Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable considering the instrument and the small pipe diameter of the affect penetr ations.

During the allowed time, a limiting event would still be assumed to be within the bounds of the safety analysis, assuming no single active failure. Allowing this extended time to potentially avoid a plant transient caused by the immediate forced shutdown is reasonable based on the probability of an event and does not represent a significant decrease in safety.

L5 In the event both valves in a penetration are inoperable, the existing Specification, which requires maintaining one isolation valve OPERABLE, would not be met and an immediate shutdown is required. The proposed ACTION (ACTION B) provides 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> prior to commencing a required shutdown. This proposed 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period is consistent with the proposed BWR Standard Technical Specification time allowed for conditions when the primary containment is inoperable. The proposed change will provide consistency in actions for these various containment degradations.

L6 The frequency of the periodic verification required when a penetration has been isolated to comply with current Specification 3.7.0.2 has been changed from daily to monthly. These valves are strictly controlled and are operated in accordance with plant procedures. Daily verification that these valves are still isolated places an undue burden on plant operations and provides little if any gain in safety, since these valves are rarely found in the unisolated condition, once closed. Note that CTS 4.7.D.2 requires the position of one other valve in the line be "recorded" daily versus the ISTS wording of "verified." ISTS also allows an inoperable valve to be used for isolating the penetration.

L7 The Note to SR 3.6.1.3.1 allows the SR to not be met (i.e., do not have to verify closed) when the valves are open for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry and for Surveillances that require the valves to be open. For these reasons, it is deemed acceptable to open the valves for short periods of time. CTS 3.7.F.3.a, which allows the 18-inch primary containment isolation valves associated with PURGING to be open during the RUN mode during a 24-hour period after entering the RUN mode and/or BFN-UNITS 1, 2, & 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.3 - PRIMARY CONTAINMENT ISOLATION VALVES for a 24-hour period prior to entering the SHUTDOWN mode, is encompassed by the provisions of the Note. The additional exemptions allowed by the Note are acceptable since the 18-inch purge valves continue to be capable of closing in the environment following a LOCA.

The time allowed to shutdown the plant when the required actions are not L8

'et has been changed from "in the COLD SHUTDOWN CONDITION within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />" to in MODE 3 (Hot Shutdown) in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 (Cold Shutdown) within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The proposed 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. The additional 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed to reach Mode 4 is offset by the safety benefit of being subcritical (MODE 3) in a shorter required time.

L9'his change adds proposed ACTION D which relaxes the allowed outage time from 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to isolate the affected penetration if one main steam isolation valve (HSIV) in one or more penetrations is inoperable (due to leakage or other reason). This will allow a longer period of time to restore the HSIVs to OPERABLE status in order to prevent the potential for a plant shutdown by isolating the main steam line(s).

During the additional time allowed, a limiting event would still be assumed to be within the bounds of the safety analysis, assuming no single active failure. Allowing this extended time to potentially avoid a plant transient caused by a plant shutdown is reasonable and does not represent a significant decrease in safety.

t BFN-UNITS 1, 2, L 3 Revision 0

4 UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

4 c., Cq on 76 ~ t ~

~

JUL 17 5%

ce t gs Itpcc fi d i a. The pressure suppression

.7.A 3.g bello vo pressure chamber-reactor building suppress on ber-reactor vacuum breakers shall be Rg(lie b'lip building vacuum breakers shall exercised in'ccordance vith 8c)oem' bc OPERABLE at all times vhcn Specification 1.0.MM an e PRIMARY COHTAIHMEHT IHTEQRITY 3.a.l,5.3 assoc ate instrumentation is required. The setpoint including sctpoint shall be of the differential pressure functionally tcstcd for SR instzlwcntatfon vhich actuates proper operation per Table 3.~.t. the pressure suppression 4 7.h chamber-reactar hi~tLag vacuum breakers shall be pcr Table 3.7.A.

Sfz.~.t.S. ~

C'crloitj and trios'om after the date b.k s that one of the pressure determination that the 5 suppression chamber-reactor force required to open each Aec, building vacuum breakers is vacuum breaker (check valve) made or found to bc inoperable does not cxcced 0.5 psid

~ t) t'f~~

for any reason, reactor operation is permissible oaly duriag the succeeding sevca days, provided that the vill be ou'tage e made each refueling

)far toH$ repair procedure does not fop et SR B u+< violate PRIMARY COHTAIHMEHT IHTE DURITY.

4e 4.

ae When primLry contaiament is a. Each dryvell-suppression required, all dryvell- chamber vacuum breaker suppression chamber vacmm ahall be tcstcd in accordance brgakera shall be OPERABIZ vith Specification 1.0.MM.

and positioned in the fully closed position (except daring testing) except as b. When it is determinedarethat specified tn 3,7.L 4.b and ceo vacmm breakers 3.74A.c., belor. inoperable for opening at a time vhen OPERABILITY is b One dryve11-suppression required, all other vacmm chamber vacuum breaker may breaker valves shall be be nonfully closed so long exercised immediately and 0 as it is determined to be not more thea 3 open as indicated by the position lights.

every 15 days thcrcafter until the inoperable valve haa tete rmal service BFR $ .7/4.7-10 AMENbMEÃf N, 2 2 2 Unit 1 PAGE PP~

TABLE 3.7.A 1NSTRNKNTATIOH FOR CONAlliiENT SYSTENS Minima No.

Operable Per Irhdeta 1nstnaent annel- .5 psld Actuat the pressure Pressure s ppresslon suppre sion chaiber-chamber-r actor building react r building vacua b eakers vacu breakers.

(Pdl 20, 21)

Footnote:

gapa)r n 2I hours. lf the fun ion ls not OPERABLE ln 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, declare th systea or coeponent lnoperabl ~ .

TABLE 4.7.A CONTAI T SYSTEN INSTRlNENTATI SURVEILLANCE REggIRENENTS n r Ins t~nt Pressure hannel-ppression Once/aonth~l) Once/1d oonthsI ) No chaebe ~

actor building vacw~ o eakers (PdIS 20, 2i)

Footnotes:

(I)

~ ) - Function teat consists of the n ection of a siaul ed si g nal into th electronic trip rcuitry in place of the sensor gnal to verify OPKRASI ITY of the trip and alara functions.

(2) - Calibr tion consists of the a justwent of the pri ry sensor and as ciated coeponent so that thev correspond within acceptable range and ccurac to %nolan val es of the parsee r vhich the chan el monitors, fncludin g ad]ustjaent of the electroni trip circuitry, so at its output r ay changes state at or core conservatively than the analog equivalent of th level setting.

UNIT 2 CURRENT TECHNICAI SPECIFICATION MARKUP

e s Aa 5R '3.

t as ~cifieL in a. The pressure suppression chamber-reactor building elo tvo pressure suppression chamber-reactor vacuum breakers shall be

~k.L%'q building vacuum breakers shall exercised in 'accordance vith BODES l~ g be OPERABLE at all times vhen 5'F Specification 1.0.MM and t e PRIMARY COHTAIHME2C IHTEGRITY associate nstrumcntation c.l,S:3 including sctpoint shall be is required. Thc setpoint 4 of the differential pressure functionally tested for proper

$g hzstrumcntation vhich- actuates operation per Table 4 V.A 3.6.l.5 3 thc prcssure suppression chamber-reactor building vacuum breakers shall bc Table 3'l.L.

Pre Sae0 Ns4C ~ At-'TIO 3. S.l.5 >

b. From and after the date v s examXaacio~

that one of thc prcssure determination that the Li suppression chamber-reactor force required to open each building vacuum breakers ia vacuum breaker (check valve)

P,c.riadS does not exceed 0.5 psid made or found to be inoperable for any reason, reactor vill bc made each refueling operation is permissible only outage.

LI p~p ~

Ac.vroWS 8 5+8 during the succeeding seven days, provided that thc repair procedure does not

'P~p~SL 3.c.J.< I violate PRIMARY COHTAIHMEHT IHTEQRITY.

4, 4, ao Shen primary containment is a. Bach dryvc11-suppression required, all dryvcll- chamber vacuum breaker auppression chamber vacuum shall be tested in accordance breakers shall be OPERABLE vith Specification 1.O.MM.

and positioned in thc fully closed position (except during testing) except aa b. When it ia detenained that specified in 3.7.A.4.b and tvo vacmm breakers are 3.7.L.4.c. ~ belce. inoperable for opening at a time vhen OPERABILITY ia

b. Onc dryvell-suppression required, all other vacuum chamber vacuum breaker may breaker valves shall bc bc nonfully closed so long cxerciscd immediately and aa it ia determined to be not every 15 days thereafter until the, inoperable valve has been more thar 3 open as indicated py the position lights. returned to normal service.

BFS 3.7/4.7-10 hMENDMBfTHO. 23 7 Unit 2 Sce ZusAC;w4gg~ t."4~~~+

4~ PF< ls7S g.g.l.g .a.-.E ~OF~

I TABLE 3.7.A INSTRUNENTATION FOR CONTAIISENT SYSTENS Hlnlaaa No.

Operabl ~ Per rk Instrument Ch nel- 0.5 paid Actuates the pressure Pressure su ress)on chamber-re tor build(ng

~

suppression chamber-vacuun b akers reactor building (PdIS 20, 21) vacua breakers.

Footnote; (l) - Raper In 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If the function $ s not OPERABLE )n 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, declare the systen or coeponent (noperable.

TABLE 4.1.A CONTAIfRiENT SYSTEH INSTRlNENTATION SURVEILLANCE REgUIRENENTS n r n h k Instrueent Channel- Onc /month Once/18 aonths None Pressure suppression chaeber-reactor building vacuum breakers (PdlS<4-20, 21)

Footnotes:

(1) - Functional est consists of the injection of a sieulat d signal into the electronic tr circuitry in place of the sensor sig al to verify OPERABILITY of the trip and alarm functions.

(2)

( ) - Calibrati consists of the ad)ustment of the prleary sensor and associated cenponents so that the~ correspond within a eptabl ~ range and accuracy to known values of the paraeeter which the channel aonltors, ncluding adJusteent of the electronic trip circuitry. so that its output relay chaqges state at or sore conservatively than

-+I the analog equivalent of the level setting.

I1J iver

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP PAGE~OF~

sfec4iM '.6 l 8 JUL 17 Q5 a . cept spec~ed a. The pressure suppression

~ oAe3eb clov vo Prcssure chamber-reactor building suppression chamber-reactor vacuum breakers shall be building vacuum breakers shall mcrciscd in accordance vith VPlimb;); be OPERABLE at all times vhcn Specffication 1.0.MM d the differential PRIMhRY COHTAIHMEHT IHTEQRITY << gt I et eeoc ated ineteueentation ia required. The aetpoiat including setpoint shall be of tha prcssure fmctfonaXXy tested for proper fastnmcntatf on vhf ch actuates operation per Table 4.7.A.

the pressure suppression chamber-reactor building vacuum breakers shall be per Table 3.7.A.

l Ao pn 5g g.e.t..

t

b. rom and after thc date b. A ion an that onc of the pressure dctcrmination that thc RCho~5 suppression chamber-reactor force required to open each A c- building vacuum breakers is vacuum breaker (check valve) made or found to be iaopcrable docs not exceed 0.5 psid for any reason, reactor vill be made each refueling pu operation fs permissible only Qu'tagce during the succecdiag seven days, provided that the repair procedure does not ~~Posgg 8R 3 4 L 5'I 8 Or+E. violate PRIllkRT COHTAINHEHT IHTECRITY

4. ess 0 ae When priory coatafnmeat is a. Each dryvcll-suppression required, all dryvell- chamber vacuum breaker suppressfoa chalbcr va~ ahall be tested in accordance breakers shaU. bc OHSABLS vith Speci ficatioa 1.0.MM.

sad positioned fa the fully closed posftioa (except during testing) czccpt as b. When it fs detezafncd that specified in 3.7.A.4,b aad tvo vacuum brcakcrs are 3.7.A.4.c belov. iaoperable for opening at a time vhen OPERABILITY is

b. One dryvcll-suppression required, all other vacuum chamber vaema breaker aay breaker valves shall be be nonfully closed so long ezercised hamediately and as it fs determined to be not aorc than 3 open as indicated every 15 days thereafter until the inoperable valve has been by the posftfon lights. returned to 1 BPH Unit 3

~

~ ~HA.ca.hb~ f 4~,

SPe lST5

~

3,g,t,g NPnMENT NO. 19 6

TABLE 3.7.A INSTRNNTATION CONAl~ Sy5Tg6 iiiniaaa No.

Operable Per XrhJiuha Instrument Channel- 0.5 paid Actuates Pressure suppression e pressur suppress on chamber-chiober<<reactor bui Ini reactor uildini vacua breakers vacu reakers.

(Pdl~20, 21)

Footnote:

(1) - Repair in 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br />. Lf the function is not OPEINBLE In 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, d clare the system or component inoperabl ~ .

TASLF. i.l.

CONT igiENT SYSTEM INSTRSKNATI SURVEILLANCE REgUIRENENTS n n h Instant Channel- Once/senth(I~ Once/18 s>>nth Pressure suppression chaeber-reactor building vacua brea'kers (PdIS-64-20, 21)

Footnote::

(11~ - Funct onal test consists f the in)ection of sisulated signal int the electronic trip circuitry place of the sans si9nal to verify ERASILITY of the t p and alarm function .

(21

( ~ - Cal bration consists o the ad)uits>>nt of he primary sensor an associated components so that correspond ui hin acceptable ran and accuracy to own values of the pa aa>>ter erich the channel aonito, c~ ncluding a justa>>nt of the el tronic trip citcu ry. so that its outp t relay changes state at or aor conservatively than

~ analog equivale of the level set ng.

tQ C>

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.5 REACTOR BUILDING-TO-SUPPRESSION CHAMBER VACUUM BREAKERS ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

A2 Existing LCO 3.7.A.3 is being replaced by proposed LCO 3.6.1.6. The proposed LCO will contain a Note stating that: "Separate Condition entry is allowed for each line." This note clarifies that the Conditions and Required Actions that follow may be applied to each of the two reactor building-to-suppression chamber vent paths without regard to vent path status. Each vent path contains two vacuum breakers in series. This note provides directions consistent with the intent of the Required Actions. This change is consistent with NUREG-1433.

TECHNICAL CHANGES - MORE RESTRICTIVE CTS 3.7.A.2.a requires the primary containment to be OPERABLE at all times when the reactor is critical or when the reactor water temperature is above 212'F and fuel is in the vessel. The proposed BFN ISTS 3.6.1.6 applicability is NODES 1, 2, and 3. This is more restrictive since CTS does not require the primary containment to be OPERABLE when in MODE 2, not critical and < 212'F.

M2 A new Surveillance Requirement has been added to verify each vacuum breaker is closed (except when they are open for performance of Surveillances) every 14 days. This is consistent with the BWR Standard Technical Specifications, NUREG 1433.

BFN-UNITS 1, 2, 8, 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.5 REACTOR BUILDING-TO-SUPPRESSION CHAMBER VACUUN BREAKERS TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" LAl Details of visual inspections of valves have been relocated to plant procedures. This type of inspection is more appropriately controlled by plant procedures. The valves are still required by Technical Specifications to be cycled and their setpoint verified to ensure operability. Any changes to procedures will be controlled by the licensee controlled programs.

"Specific" Ll Existing LCO 3.7.A.3.b identifies the currently required actions if one reactor building-to-suppression chamber vacuum breaker is inoperable.

If more than one vacuum breaker is inoperable, the existing specification assumes either containment integrity is lost or the ability to relieve negative pressure in the containment is lost.

Therefore, LCO 3.7.A.3.b. defaults to 1.0.C. 1 which requires that the reactor be placed in Hot Standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Cold Shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Proposed LCO 3.6. 1.6 recognizes that there are two vacuum breakers in series in each of two vent paths between the reactor building and suppression chamber. As a result, if one vacuum breaker in each vent path is not closed (Condition A), containment integrity and venting capability are still maintained and 7 days is provided to restore the redundancy for containment integrity in each vent line. Likewise, if two vacuum breaker valves in one vent line are inoperable but closed (Condition C), containment integrity and venting capability are still maintained and 7 days is provided to restore the redundant vent path. Therefore, proposed Specification 3.6. 1.6 makes the distinction between loss of redundancy and loss of function. The existing specification fails to make this distinction between loss of function and loss of redundancy and, therefore, is unnecessarily conservative. In addition, loss of function (loss of containment integrity (Condition B) or loss of venting capability (Condition D))

will require initiating action within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> instead of immediately.

Also, CTS 3.7.A.3 does not have a specific shutdown requirement, therefore, CTS 1.0.C. 1 applies. CTS 1.0.C. 1 requires the unit be placed in Hot Standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Cold Shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Proposed ACTION E requires the Unit to be placed in Hot Shutdown with 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Cold Shutdown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Proposed ACTION E is considered less restrictive since additional time is allowed prior to requiring the plant to be in a lesser Node (i.e., Proposed Action E requirement to be in Hot Shutdown in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> versus the CTS requirement to be in Hot Standby in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />). This change is consistent with NUREG-1433.

BFN-UNITS 1, 2, L 3

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.5 REACTOR BUILDING-TO-SUPPRESSION CHAMBER VACUUM BREAKERS L2 The vacuum breaker actuation instrumentation Surveillances are proposed to be deleted from Technical Specifications. The requirement of SR 3.6. 1.5.3 to ensure the vacuum breakers are full open at 0.5 psid is sufficient. Vacuum breaker actuation instrumentation is required to be OPERABLE to satisfy the setpoint verification Surveillance Requirement (SR 3.6.1.5.3) for the vacuum breakers. If the vacuum breaker actuation instrumentation is inoperable, then the Surveillance Requirement cannot be satisfied and the appropriate actions must be taken for inoperable vacuum breakers in accordance with the ACTIONS of Specification 3.6. 1.5.

As a result, the requirements for the vacuum breaker actuation instrumentation are adequately addressed by the requirements of Specification 3.6. 1.5 and SR 3.6.1.5.3 and are proposed to be deleted from Technical Specifications.

BFN-UNITS 1, 2, 8L 3 Revision 0 PAGE ~ OP~

CURRENT TECHNICAL SPECIFICATION MARKUP

3.7.A 4.7.A 3~ 3~

aes ao Except as specified in a. Thc prcssure suppression 3.7.A.3.b bclov, tvo pressure chamber-reactor building suppression chamber-reactor vacuum breakers shall be building vacuum breakers shall exercised in accordance vith bc OPERABLE at all times vhen Spccificatioh 1.0.MM, and the PRIMARY COHTAIHMEHT IHTEGRITY associated instrumentation is required. Thc setpoint including setpoint shall be of the differential pressure functionally tested for instDKcntatioa'vhich proper operation per Table 4.7.k.

actuates'he prcssure suppression chamber-reactor ~Bag vacuum breakers shall be pcr Table 3.7.A.

b. Prom and after the date b. A visual examination and that one of thc prcssure dctcrmination that the suppression chamber-reactor force required to open each building vacuum brcakcrs is vacuum breaker (check valve) made or found to bc inoperablc docs not exceed 0.5 psid for any reason, reactor vill be made each refueling operation is permissible only outagee during the succeeding seven days, provided that the repair procedure does not violate PRIMARY COHTAIHMEHT IHTEGRITY.

SR

~) >C4pif> . When pr containment is a. Each dryvell-suppression required all dryve

~)

NoQP5 chamber vacuum breaker I,>+3 suppression chamber vacma shall be tcstcd in accordance breakers shall be OPERABLE vith Specification 1.0.ÃM.

LI:o sad positioned in the fully PAc>I>c>s+ SC, 3 6> !.6>> I closed positioa ~ocg4-3,G, I.b

b. When tvo vac it is bre determined tha rs ar

~h c n .7. 4.

pal Q~'>>>g

..c b er. perab for o ng t a

&Cia >hg>>>IgcI, t vhea is

b. One dryvcll suppression re ired, othe vac HQ chamber vacuum breaker may bre r valv shall be bc nonfully closed so long merc ed imm iately and 4o jg as it is determined to be not every days thc inop rable ereaft uati lve ha been more thm 3 open as indicated by the position lights. returaed rmal service.

f JOt'~+ ACTIoQ A 8.7/4.7-10 BPH LI hMENbMEÃf 50. 222 Uait 1 4 2, pAGE~OF~+

0 gR 3.4. I ob 3

c. zo 4ryvell-suyyrcssioa chamber vacuum breakers shaL) be inspected for may be determined.to be prayer operation of the yerable for op~ valve and 1&" wi-""cs ance v1

~c V~ s wQ~~

QvC~~gp g+~

Syecat'n L. Q .. !. Fo isvS S.I,<.l QC7(onl S pec'cat'oas 3.7.4.4.a, 4. k Leak test of the dr.~cl C- 3.7.4.4.b, or 3.7.L.4.c. to suppression chamber cannot be met, the st~cure shaLL be conducted unit shall be placed ia a each operating cycle ~

, COLS SHUTDOWN CQHDITIOH ia acceptable leak rate is an orderly manner i%thin 0.09 Lb/sec of yrimazy hours. In a HoT5guTDo~A coatainmeat atmosphere vith 3I L4 Andi H on Jn INA<S 1 psi diffe cntiaL.

5 ~

a. Containmeat atmosphere shall be a. The primary coataiamcat

'educed to less than 4% oxygen oxygea concentration shall vith aitrogea gas during reactor be measured aad recorded

~ pover operation vith reactor daily. The oxygea coolaat pressure abore 100 psig, measurement shall be ad]usted except as syecified in 3.l.i.5.b. to account tor the uncertainty of the method used by adding a predetermined error funct'oa

b. Within the 24-hour yeriod b. The methods used to measure subsequent to ylaciag the reac or the yrimary contaiameat ia the RUH NDE folloviag a shut- oxygen concentration shaLL dova, the coataiameat atmosphere be calibrated once every oxygen coacentrat'oa shall be refueling cycle.

reduced to Less than 4" by volume aad maintained ia this condit'oa.

Deiaertiag may commence 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a shutdovn.

c. If plant control air is being used c. The coatrol air suyply valve for the pneumatic control to suyyly the pneumatic coatrol system ~ide primary containmcat, system'inside thc prmar/

the reactor shall not be started, containment shall bc vcr'f'cd or if at, pover, the reactor shall closed prior to:eac or star='

aad monthLy thercait .".

be brought to a COLD SHUTDOM5 CQHDI OH vithia 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4. If Specification 3.7.h.S.a and ~'"~urn A r Oramong 3.7.A.5.b cannot be met, aa RR 8FAl (5T5 orderly shutdova shall be initiated and the reactor shall be ia a COLD SHGTDOMH COHDITIOH vithia 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

BFH .7/4.7-11 AMENDMENT NO y~ 9 Unit 1 3 r'g

UNIT 2 CURRENT TECHNICAL SP ECIF ICATION MARKUP

0 0

s.v.a 4.7.h 3~ 3~ Su Except as specified in a. The pressure suppression 3 'ohe3eb beloved tvo pressure chamber-reactor building suppression chamber-reactor vacuum breakers shall be building vacuum breakers shall exercised in accordance vith bc OPERhBLB at all times vhen Specification 1.0.MM, and the PRIORY COHThIRNEHT IHTEGRITY associated instrumentation is required. The setpoint including setpoint shall be of the differential pressure functionally tested for proper imtnacntation Mch- actuates. opcratioa par Table-4 ZA the pressure suppression chamber-reactor building vacuum breakers shall be yes Table 3'7.k.

b. From and after the date b. h visual examination and that one of the pressure determination that the suppression chamber-reactor force required to open each building vacuum breakers is vacuum breaker (check valve) made or found to be inoperable. does not exceed 0.5 psid for any rcuon) reactor vill be made each refueling operation is permissible only outagce during thc succeeding seven days, provided that the Sqe a~a4'i/i'(aA'oe For C4o~pSX repair procedure does not g~ BpN (sos a.C. (,g violate PRINhRY COHThIHMEHT IHTEQRITY.

Al Pht

+f ltC4~e t< sp s.c./.t" ~

pcibEs ao When primary conta ent is

/~L f e ed all dryvell- chamber vacuum breaker suppression chamber vacuum shall bc tested in accordance t c,o breakers shall be OPERABIS vith Specification 1.0.MM.

z.c,(.6 Pl and positioned in the fully Pr~ sg, p, g. (. g (

M <n pW4g closed position 4emeege i'4c'~;~~ ) exc tas en t s e e ed that Curbs aps .7.h.i. P l tvo vacma b a are 371.4 ~ inoperable for at, h t shen 0 is

b. OILc dryvcll suppression r br rsd, all other valves shall b~

cd PoQ 2. chamber vacuum breaker msy bc nonfully closed so long exercis immediately and~

sR z.c,.l,b.l as it is determ~ to be not every 15 s thereafter until more tban 3 open as indicated the inoperab valve has been by the posit'ion lights. returned to normal service.

BPS ~~op~ 4erroN A 3.7/4.7<<10 Nettegpgg. 2p q Unit 2 LZ ~"0 ~ pc~<<~ 8 PAGE W GF

S . liea lichen 3, g. I. 6 1S88 tt =

l ~

4~

~ I, 3

c. Tvo dryvell-suppression C Each vacuum breakc valve I Co3(.lk chamber vacuum breakers

~

shall be inspected'or may be determined to be proper operation of the inoperable for opening. valve and limit sv'tches I in accordance vxt SgpawsTi<iCATi4~

cification 1.0.:R &R-CII"+~~

IIfN sS 7 S 3.4,. I I

d. If Speci fications 3.7.A.4. a, A e test of the d./well AfVIoH .b, or .c cannot be met, the to suppression chamber unit shall be pl'aced i structure shall be conducted Cold Shutdovn condition in during each operating cycle.

an orderly manner vithin Acceptable leak race gs ours ~ 0.09 lb/sec of primary 96 g.s s<~ ~~ containment atmosphere with 1 psi differential.

co~a 4

5. 0 a 5. 0 Co tao Containmeat atmosphere shall be a. The primary containment reduced to less than 4X oxygen oxygen concentration vith nitrogen shal'e gas during reactor measured aad recorded power operation vith reactor daily. The oxygea

.coolant prcssure above 100/psig, measurement shall be adjusted except as specified in 3.7.A.5:b. to accouat 'for thc uncertainty of the method used by adding a predetermined error function.

b. Mithin thc 24-hour period b. The methods used to measure subsequent to placing the reactor the primary containment in the BUH mode folloving a shut- oxygea concentration shall dovn, the containment atmosphere bc calibrated once every oxygen concentration shall bc refueling cycle.

reduced to less than 4X by volume and maintained in this coaditioa.

Deinerting may commence 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a shutdova.

c. If plant control air is being used c. The control air supply valve to supply the pneumatic coatrol for the pneumatic control system inside primary coatainment, system inside the primary the reactor shall aot be started, containment shall be verified or if at power, the reactor shall bc:brought to a Cold Shutdown closed prior to reactor startup and monthly thereafter.

condition vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

d. If Specificatioa 3.7.A.5.a aad 3.7.A.5.b cannot bc met, an orderly shutdovn shall be initiated and the reactor shall SFE'us7 IFICA7innJ F'og in a Cold Shutdown condition vithin 24 hours.

be g~nl i~ 3.4.B,J QHA>GES'oR BiH Unit 2 3.7/4.7-11 Mi'40M'.ir. i 5 -

PPQL op~

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP PAGE~OF

3.7.h 4.7.h 3~ ambe-1zuU<era aa Except as spccificd in a. The prcssure suppression 3.7;h.3.b bclov, tvo prcssure chamber-reactor building suyprcssion chamber-reactor vacuum breakers shall be building vacuum breakers shall exercised in accordance vith be OPERABLZ at all times vhcn Specification 1.0.MN, and the PRIMARY COHTAIHMEHT IHTEt RITY associated instrumentation is required. The aetpoint including sctpoint shall be of tha difforcaaf.al prcssure fictionally ecstcd for prop inatrL<<lcntation vhich actuates operation per Table 4.7.h.

the prcssure suppression chamber-reactor building vacuu<< breakers shall be per Table 3.7.h.

. From and after the date b. h viaual examination and that one of the pressure determination that the suppression chamber-reactor force required to open each building, vacuum breakers ia vacuum breaker (check valve)

<<adc or found to be inoperablc does not exceed 0.5 psid for any reason, reactor vill be made each refueling oyeration ia permissible only outagee during the succeeding seven days, yrovided that thc 5'~< 5uSACi cab'on Qr ChanyrZ repair procedure does not +a di< l S Ts 3.c.!-5 violate PRIMARY C02ITAIHMENX'ITECRITX, 4.

se 3...c-.

>aabalkj a %hen pri<<ary contain<<ent ~ a. Ea dryvcll-suppression OOeS lp.< required chamber vacuum breaker auypreaaion cha<<ber vacmm shall be tested in accordance LM braakcra shall be OPERJBIS vith Specification 1.0.MN.

and positioned in the fully tl C I. C.

!\

i@hen ~ get~~ Opt as b. Shen t a deter<<ined that

~ir tn~ pec .7.l.4~1 and two va breakc are

.7.A.. bclov. inopcrabl for open ng at a ti<<e vhen ILI is

/} b. One dryvell-suppression squired~ other v uum chamber vacmm breaker <<ay b esker valv shall b be nonfully closed so long ex ciaed imm ately aa it ia determined to be not eve 15 days th reafter the in erablc va ve has ecn til

<<orc than 3 oycn aa indicated by the position lights. return to normal ervice flo OQCA ftg70n, '/4.7-10 BFK 3 NB:AMENT No. ~ 9 6 Unit 2 ro iong ch'on p,a GF:~QF~

~ p> ~ ~ c. Tvo drywell-suppression chamber vacuum breakers 5 3'.t'o. I. 4 C~

~

Once each operating cycle, each vacuum breaker valve may.be determined to be shall be inspected for inoperable for opening. proper operation of the valve and limit svitches 3 n accordance v t Specification 1.0.MM ..

d. If Speci fications 3.7.A.4. a, d. h leak test of the drywell 3.7.A.4.b, or 3.7.A.4.c, to suppression chamber cannot be met, the structure shall be conducted unit shall be placed during each operating cycle.

in a Cold Shutdown Acceptable leak rate is condition in an orderly 0.09 lb/sec of primary manner vithin rs ~3' containment atmosphere vith CA/ 1 si differential ye~~~f

~'hen f/n584TSecP V~S.hQ'aCHO o wars r so~

LSqs R.r

a. Containment atmosp ere shall be a. The primary containmen reduced to less than 4X oxygen oxygen concentration sh 1 vith nitrogen gas during reactor be measured and recorded pover operation vith reactor daily. The oxygen coolant prcssure above 100/psig, measurement shall be ad)usted except, as specified in 3.7.A.5.b. to account for the uncertainty of the method used by adding a predetermined error function b.. Wi,thin the 24-hour period b. The methods used to measure subsequent to placing the reactor the primary containment in the RUH mode folloving a shut- oxygen concentration shall dovn, the containment atmosphere be calibrated once oxygen concentration shall be cycle. every'efueling.

reduced to less than 4X by volume and maintained in this condition.

Deinerting may commence 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to a shutdown.

c. If plant control air is being used C~ The control air supply valve to supply the pneumatic control for the pneumatic control system inside primary containment, system inside the primary the reactor shall not be started, containment shall be verified or if at pover, the reactor shall closed prior to reactor startup and monthly thereafter.

be brought to a Cold Shutdovn condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

d. If the specifications of 3.7.A.5.a through 3.7.A.5.b cannot be met, an orderly shutdown shall be initiated and the reactor shall be in a Cold Shutdown condition vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. AMEN87tlE~IT. AO. 1 8 0 BFH .7/4.7-11 Unit 3

I3USTIFICATION FOR CHANGES BFN ISTS 3.6.1.6 SUPPRESSION-CHAMBER-TO-DRYWELL VACUUM BREAKERS ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is'lready approved, adding more detail does not result in a technical change.

A2 The words "except when performing their intended function" have been added to preclude requiring the LCO to be met when the valves cycle automatically. Since their intent is to open when a sufficient differential pressure exists, this change is considered administrative only.

A3 CTS 4.7.A.4.c is performed in accordance with the Inservice Testing Program on a frequency of every operating cycle. Proposed SR 3.6. 1.6.3 is to be performed every 18 months. Since an operating cycle at BFN is approximately 18 months, this .change is considered administrative.

TECHNICAL CHANGES - MORE RESTRICTIVE Ml CTS 3.7.A.2.a requires the primary containment to be OPERABLE at all times when the reactor is critical or when the reactor water temperature is above 212'F and fuel is in the vessel. The proposed BFN ISTS 3.6.1.6 applicability is MODES 1, 2, and 3. This is more restrictive since CTS does not require the primary containment to be OPERABLE when in, MODE 2, not critical and < 212'F.

M2 A new Surveillance Requirement (proposed SR 3.6. 1.6.1) has been added to verify the vacuum breakers are closed once every 14 days. This new SR ensures the "closed" requirement of the LCO statement is being met.

This is an additional restriction on plant operation.

BFN-UNITS 1, 2, 5 3 Revision 0 PAG~(

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.6 SUPPRESSION-CSNBER-TO-DRYWELL VACUUN BREAKERS M3 CTS 3.7.A.4.d requires an orderly shutdown be initiated and the reactor to be in the Cold Shutdown Condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when certain conditions can not be met. Proposed Action C will require the plant be in MODE 3 (Hot Shutdown Condition) in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and NODE 4 (Cold Shutdown Condition) in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The addition of this intermediate step to the Cold Shutdown Condition is considered more restrictive since CTS does not require any action to have taken place within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. 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 safety systems.

TECHNICAL CHANGES - LESS RESTRICTIVE "Specific" Ll Proposed ACTION A allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to restore an inoperable vacuum breaker to OPERABLE status, with one of the required vacuum breakers inoperable for opening. This is allowed since the remaining nine OPERABLE breakers are capable of providing the vacuum relief function.

The 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is considered acceptable due to the low probability of an event in conjunction with an additional failure in which the remaining vacuum breaker capability would not be adequate.

L2 Proposed Action B allows a short time to close an open vacuum breaker since there is low probability of an event that would pressurize primary containment. An open vacuum breaker allows communication between the drywell and suppression chamber airspace and, as a result, there is the potential for suppression chamber overpr essurization due to this bypass leakage if a LOCA were to occur. If vacuum breaker position indication is not reliable, an alternate method of verifying that the vacuum breakers are closed is to verify that a differential pressure of 0.5 psid between the suppression chamber and drywell is maintained for I hour without makeup. The required 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is considered adequate to perform this test.

L3 Existing Specification 4.7.A.4.b requires that "When it is determined that a vacuum breaker is inoperable for opening at a time when operability is required, all other vacuum breakers shall be exercised immediately and every 15 days thereafter until the inoperable vacuum breaker has been returned to normal service." This requirement is not included in NUREG-1433 and will be deleted. This change eliminates the requirement to demonstrate the OPERABILITY of the redundant vacuum breakers whenever a vacuum breaker is declared inoperable. This change acknowledges that the inoperability of a vacuum breaker is not automatically indicative of a similar condition in the redundant vacuum breakers unless a generic failure is suspected and that the periodic BFN-UNITS I, 2, 5 3 2 Revision 0

=-'".F 2

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.1.6 SUPPRESSION-CHAMBER-TO-DRYWELL VACUUM BREAKERS frequencies specified to demonstrate OPERABILITY have been shown to be adequate to ensure equipment OPERABILITY. Therefore, this change allows credit to be taken for normal periodic surveillance as a demonstration "

of OPERABILITY and availability of the remaining components and reduces unnecessary challenges and wear to redundant components.. This change is consistent with NUREG-1433. '

L4 CTS 3.7.A.4.d requires the unit to be placed in a Cold Shutdown condition in an orderly manner within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Proposed ACTION C is less restrictive since it requires the unit to be placed in MODE 3 (Hot Shutdown condition) in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 (Cold Shutdown condition) in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. 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.

BFN-UNITS 1, 2, 8L 3 Revision 0 PAGE~OF~

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

Cp 5Pec.,loot.o Z (. Z i

~ 7 4.7 ab Appli s to the o rating st us plies to th primary and of the primary an secondary s ondary conta nment contai ent system in grity.

~Q(~~v To assure t e integrity f the To veri the integrity of the primary and econdary primary d secondary containment stems. containment.

l. At any time that the irradiated fuel is in thc AppVcab>)<ky reactor vessel, and the nuclear system is pressurized a. e suppression above atmos heric ressure chamber vater level c Such('ca@on or vor is being done vhich 6 r cnanges p, BFg bc checked once has the potential to drain Is~s 3.s.x Whenever hea~P.s.g.q,t,)

hc vessel the pressure is added to the su pression oo r lcvc suppression pool by an empcrature shall be testing of the ECCS maintained vithin thc or relief valves the following limits. pool temperature Sec Vusghuh'~n shall bc continually Q~ cgae6 ts monitored and shall be observed and

a. Minimum vater level ~ Pr gFg Zygo logged every

-6.25" (differential 5 minutes until the prcssure control >0 psid) heat addition is

-7.25" (0 psid differen- terminated.

tial prcssure control)

AM 5'Ra.g.~,t.l f <s~

b. Mazimum vater level =

lit frequency -~ce/s pp~,>

3.7/4.7-1 Unit 1 PAGE W OP>

0

~p<<il'ca8rn 3. L.Z. /

AU8 23 1991 f4+eel pg~',<eg Re%on

~ ~

BcT(oA A Cond iHOn 8 c. ith the suppression pool p leo 3,Q,g,f water temperature > 95'F 3 initiate pool cooling and QeR~~Q estore the temperature fk+iOn g,2 o g 95 F vithin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or e n at LI least H OWH LI COHDITIOH vithin thc next Alen pny os<A>'iE, +p~ p 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in the >5/Vo Cia;s~op h,il ACT(oe COLD SHUTDOWH COHDITIOH 8 ~<+1< on gran I o<u'ref agon vithin the folloving e 7 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

D,g 54TIOpJ d. With the suppression gCt 3.C.w.l.k Conlitjon Q C pool vater temperature

> 105'F during testing Rca ~red of ECCS o relief WvuN @el valves, top all LQ t test ng, it ate oo o follov thc

t. act on in Specification g ~$ 3.7.k.l.c above.

e. With thc suppression c.co 3.6 0 1.4 pool vater temperature )

Cond,yn P > 110~P rOPPli a&iI '+y OHDITIOH, HOT SThHDBY Wches t g 4-g COHDITIOH (with all control rods not inserted), or REh OWER OPERATION the reactor s c Aa~ o,i l scr P ~e RCRaaio<gf +c+jo~ g With the suppress'ion

~lo/V C~;t 6'

pool vatcr temperature 120'P o ov ng E reactor isolation epressurize to

< 200 psig at normal

'P coo rates.

BFH 3.7/4.7-2 AMENGMENT No. I 85 Unit 1 PAG'E

UNIT 2 CURRENT TECHNICAL SP ECIF ICATION MARKUP

LI 3.7 0 S S 4.7 CO S S b

Applies to the crating status h lies to the pr ary and f the primary secondary sec dary containme c tainmenH syst integ ty.

be ve ~0b ~v To assur the integrity of e To verify th integrity of the primary secondary rimary and secondary containment ystems. containment.

ht any time that the irradiated fuel is in the Aqui'eaQ,@ reactor vessel, and the nuclear system is pressurized a. The suppZession above atmospheric pressure ~~s ~~ flclfP chamber water level or wor s e ng one which has the potential to drain A g,

~

C,HhM<~

its).S.Z be checked once er day. Whenever hea~SR36i~ I the vessel the pressure s added to the suppressi ater leve suppression pool by emperature shall be testing of the ECCS maintained within the or relief valves the following limits. em Sus TIFI c'ATI4N pool temperature shall peg CHAN pcs be continually t-o g. BFN >.6 z 2 monitored and shall be observed and logged

a. Minimum water level = every 5 minutes

-6.25" (differential until the heat pressure control >0 paid) addition is

-7.25" (0 psid differen- terminated.

tial pressure control) kid. sn s.a.~.l I 4"~

b. Maximum water level ~

1 tl 4 <y <WC~- n CA./Z'll l4 5 BFH 3.7/4.7-1 Unit 2 PAGE A GF ~

NQY 18 ]988

>iopoSc4 (2C)~'rC4 Ac+un 4 t Cvloh/ A ith the suppression pool J vater temperature > 95'F 0~

QAClo ~

nitiate pool cooling and gpgur rQ restore the temperature pc.kid~ A 2- to g 95'F vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> o be in at east t e HOT SHUTDOWH 4/ COHDITIOH vithin the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in the QcTr o COLD SHUTDOWH COHDITIOH 8 vithin the folloving gegwsr+ )le id'.3 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> ith the suppression g.c.z.J 6

/ 105'F during testing of ECCS or relief Ping,~',re> valves, stop all Ae4;o~ e.i testing, t turbo 1 follov the J4.Tio~ q action in Specification 3.7.h.l.c above.

pc.Tla< e~ With the suppression geo g.c.2.l. c pool vater tern erature

> 110'F during the STAR App),c,'Ll,~y OHDITIOH, HOT STANDBY Naos l~ Z +5 COHDITIOH (vith all control rods not inserted), or REACTOR WER OPERATIO the reactor shall be 7eg.

Aek~~b.

g sc ed i Pr o go ~ Pe u. t a8 A(4o e D ~

f. With the suppression Co4<<.c E pool vater temperature 4'>oN 120'F folloving E reactor isolation epressurize to

< 200 psig at norma oo ovn rates.

3.7/4.7-2 AMENDMENT NO. y5 4 Unit 2 PAGE ~ OF

0 UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

~ 7 4.7 Appli to the operating status Applies to the rimary and of the rimary and second econdary conta ent containm t systems. tegrity>>

To assure th integrity of the To ver fy the integri of the primary and s ondary primary secondary tainment systems ~

containment'.

At any time that the irradiated fuel is in the pyi;(gb,f, p] reactor vessel, and the nuclear system is pressurized SCC $g5tgWh4+

a. The suppression above atmospheric ressare chamber water level Foi Chan)t.'<

r wor s e done which be checked once er

~ vesselpotential to the the dra the pressure

& pe i5fb i S.w day. Whenever heaW>R w aLt s added to the ress on ol ster leve suppression pool by 1 e testing of the ECCS maintained within the or relief valves the

'following limits. pool temperature shall Yuc8A'colon be continually Ai Chan)C'j 0 i monitored and shall be 1<4 34,a x observed and logged

a. Ninimam water level ~ every 5 minutes

-6.25" (differential until the heat pressure control >0 paid) addition is

-7.25" (0 paid differen- terminated.

tial pressure control)

Afd sP.F.( .zeal.l Arsw

b. Haxlanm water level ~

lit FV<z~emy-once Qfpsurg BFE 3.7/4.7-1 Unit 3 PAGE OF

SR.~;g~~ Z.g.2. t NDV is Z88 ProgoLcd CCq~;rc Co With the suppression pool Lco Z. 6.2.l.a

' vater temperature > 95 F c'.

~4> fun tiate pool cooling, and restore the temperature AA4Lsrg ~ to g 95'F vithin A4tfon hL 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> r e at LI east the HOT SHOTDOW5

&pen oPVRRO)E ~m cWh~

CONDITION vithin the cchy

~

next 6 hours and in the Q5/ t~ cf>u>sion 4I Bell Scolc hon COLD SHUTDOWN CO%)ITI01 R~c 7 AL vithin the folio~

khaki(c 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />

d. ith the auppreaaicm 1 vater temperature

~ g,e.2.l.b

+bio n C. 105'F during testing f HCCS or relief Ro alvea top all

+~one' testing, a 'po o ov the ee on in Specification 3.7.k.l.c above.

With the suppression L~ g,C.Z.l. c pool vater t eraturel Ipe4>n > )104 ur 'the S Afflr'CebrlS7 l' D HDITI01, HOT STh2IDBY muon f"a+3 CONDITION l,'vith all ccmtrol rods not inserted), or 0 the Pea ircA ~

hc Yon p. l reactor shall be totogc c~,'c hm

f. With the suppression C~l Ken E pool vater temperature

> 1204F o lo

]KHo reactor iaolaticm, epreaaurize o c 200 pai norma coo ovn rates.

BF5 Unit 3 3,7/4.7-2 AMENDMENT NO. j2 9 PAGE' OF 3

0 JUSTIFICATION fOR CHANGES BFN ISTS 3.6.2.1 - SUPPRESSION POOL AVERAGE TEHPERATURE ADHIN ISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no.technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

TECHNICAL CHANGES - NORE RESTRICTIVE

~ M1 Existing Specification 3.7.A. l.e modifies the applicability governing suppression pool temperature such that the temperature limit applies only during the STARTUP CONDITION, HOT STANDBY CONDITION (with all control rods inserted), or REACTOR POWER OPERATION. Proposed LCO 3.6.2. 1, Suppression Pool Average Temperature, ACTION D is applicable in Hodes 1, 2, and 3. Therefore, this change is more restrictive.

H2 CTS Surveillance Requirement 4.7.A. l.a only requires continual suppression pool temperature monitoring and logging whenever heat is added to the suppression pool during testing. Proposed SR 3.6.2.1. 1 is more restrictive since it also requires this verification be performed once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in the absence of testing.

A new Required Action has been added (proposed Required Action A.l) to verify temperature is c 110'F every hour, anytime temperature has exceeded 95'F. This is an additional restriction on plant operation.

H4 When temperature exceeds 110'F, the current requirements only require the reactor to be scrammed. Proposed Required Action D.2 requires the temperature to be verified a 120'F every 30 minutes and a cooldown to HODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, respectively. If temperature exceeds 120'F, the current requirements only require the RPV to be depressurized to < 200 psig at normal cooldown rates. Proposed ACTION E now requires the 200 psig limit to be attained in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, and to continue cooling down the plant to cold shutdown (HODE 4) within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. These are additional restrictions on plant operation.

BFN-UNITS 1, 2, 5 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.2.1 - SUPPRESSION POOL AVERAGE TEMPERATURE The proposed ACTION (ACTION E) when pool temperature exceeds 120'F does not depend upon whether the reactor is isolated. If pool temperature reaches 120'F, regardless of whether the reactor is isolated, significant heat could still be added to the suppression pool and the Required Action is appropriate. Even with the reactor not isolated, there may be no heat rejection from the containment, as in the case of loss of condenser vacuum. Applying the actions regardless of whether the reactor is isolated does not introduce any operation which is unanalyzed. This change is more restrictive on plant operations.

TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" LA1 Details of how to reduce suppression pool temperature to within the limits have been relocated to plant procedures. Methods for restoring pool temperature are more appropriately located in plant procedures.

Changes to the procedure will be controlled by the licensee controlled programs.

"Specific" The Applicability for proposed LCO 3.6.2. 1, Suppression Pool Average Temperature, is Modes 1, 2, and 3. However, this Applicability is modified within LCO 3.6.2. 1 so that a lower suppression pool temperature limit applies if any Operable IRM channel is on Range 7 or above. This limit was selected so that the suppression pool temperature limits are applicable when the reactor is critical with reactor power approximately at the point of adding heat. As a result of this qualification to the Applicability statement, suppression pool temperature is required to be maintained at a temperature of less than 95'F (or less than 105'F while performing tests that add heat to the suppression pool) only when the reactor is critical with reactor power at the approximate level where heat generated is approximately equal to normal system heat losses. If the reactor is not critical or at a power below the point of adding heat, the suppression pool may be maintained at an average temperature up to 110'F. This change is less restrictive because CTS 3.7.A. 1.

required the lower suppression pool temperature to be less than 95'F (or less than 105'F while performing tests that add heat to the suppression pool) even if the reactor is not critical or not above the point of adding heat. If the reactor is not critical or the reactor is below the point of adding heat, there is significantly less heat generation from decay heat than assumed in the design basis. The suppression pool is designed to absorb the decay heat and sensible energy released during a reactor blowdown via safety/relief valves or from design basis accidents when the reactor has been operating continuously at full power for a BFN-UNITS 1, 2, 5 3 Revision 0 pAGE~OF~

0 JUSTIFICATION FOR CHANGES BFN ISTS 3.6.2.1 - SUPPRESSION POOL AVERAGE TEMPERATURE considerable period of time. Any event initiated with reactor power or reactor power history less than these conditions will place considerably less heat load on the suppression pool than a DBA LOCA. This change is consistent with NUREG-1433. In addition, the shutdown requirements, if the temperature is not restored, have been modified to only require reducing power to below IRH Range 7 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, consistent with the new Applicability.

BFN-UNITS 1, 2, 5 3 Revision 0

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

4.7 ab Applic to the opc ating status A lies to thc p imary and of the imary and econdary se ndary contai t containm t systems. inte rity.

~0i~~v To assure the tegrity o primary and secondary the To verify he integrity f the primary and ccondary ontainmcnt systems. ontainm A.

1. At any time that the

~)<cobe]july irradiated fuel is in the reactor vessel, and the nuclear system is pressurized a. Thc suppression above atmospheric pressure chamber vater level ng one vhich JILS fjA~Oh bc checked once per has thc potential to drain Ar Ckg~~ Wc day cne r eat Ph IsTS 3,5,2 thc vessel e pressure s added to thc suppress on pool vater level suppression pool by an tern cra ure shall bc testing of the ECCS maintained vithin t e or relief valves the folloving limits. See'u~ h ~qg>~ ool temperature shall be continually A Oa~~ &r c

monitored and shall 3, Q. 2,I SF'S75 be observed and

a. Mininnnn vater level ~ logged every

-6.25" (differential 5 minutes until the pressure control >0 psid) heat addition is

-7.25" (0 psid differen- terminat8d.

tial pressure control)

b. Maximum vater level ~

1N LI fr'~ gaioeR L~ I~<4 heres s BFH 3.7/4.7-1 Unit 1 PP,QE~OF

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP

0 SE'C <csdifiqih~ ~c -P4i'.>4ira, (o Z4'. 2.

C~4~Pt Q~ $ fhl (STT >.4,g.l A>

4.7 plies to the opc ting status hppl s to the prima and of c primary and s condary scc ry containment coat iameat systems. integri 0 Qhiee~~ X To assure he iatcgrity of To verify the tegrity of the primary aa secondary primary and seco ary containment stems. ontainmcnt.

P~i;ops,'/Igy I. ht, any time that thc g( ~

irradiated fuel is in the reactor vcsscl, and the SR 3.<,z.z. I nuclear system is pressurized ao Thc suppgession above atmospheric prcssure chamber vater level or vork is being done vhich SM MS TIFicATIod bc checked once per FoR CHAA WS Fog.

has the potential to drain LFN iSlX 3.5;2. day. Whenever eat the vessel e pressure s a ded to the suppression pool vater level suppression pool by erature hall be testing of the ECCS ma nta ned vithin t e 3eE'g EST ifiCA7lohJ or relief valves the folloviag limits. FoR Hhuo'es ~g D&l isis 3.g z I pool temperature shall be continually monitored and shall be observed and logged

a. Minimum vater level = every 5 minutes

-6.25" (differential until the heat pressure control >0 psid) addition is

-7.25" (0 psid differen- terminated.

tial pressure control)

b. Maximum vater level ~

1 tt

')cScd AC.TiO+ P, L~ P opo5ed ACTioN 8 BFH 3.7/4.7-1 Unit 2 PAGE~OF~

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP OF 2,

pAGE

ace r~y~soo kv Chape Ate SftCS'ECCL 9% o 6e2 ~

ni 3.7 4.7 hpplie to the operating tates hppliea to the imary and of, the p and second econdary conta ent n containm 'aystcsls e egrity.

To assure the egrity of the To ver the integri of the primary and sec primary secondary containment syat contalnm t.

.. 1 it any time that the irradiated fael la ln the Maahm reactor vessel, ancL the SR Z,t,.z.z,t nuclear system ls preaanrixed a. The suppression above atmospheric pressure chamber vater level r vorR ia e

~ vesselpotential to draln the the e

one pressure ch be checked once per day. whenever s added to the a

reaaion ol eater level suppression pool by and t crater 1 be testing of the ECCS Ll:o 3'.4.2, ma tained the ~c'~4cahq r relief valves the

'follovtng limits. +c~ ol temperature shall SF'sis 9.g.y. be continually monitored and shall be observed and logged

a. Minimum vater level ~ every 5 minutes

-6.25" (differential See aeggiaatjon until the hea pressure control >0 paid) 6c'harta &a addition la

-7.25" (0 paid differen- bN iSv3'z.s,z. terminat tial pressure control)

b. Haxha~ eater level ~

lit QLl ~e'cct )kwon it

c. W &coon 8 BFÃ 3.7/4.7-1 Unit 3

t BFN ISTS ADNINISTRATIVE CHANGES Al JUSTIFICATION 3.6.2.2 -

FOR CHANGES SUPPRESSION POOL WATER LEVEL Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be mor e readily readable, and therefore, understandable by plant operators as well* as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

TECHNICAL CHANGES - LESS RESTRICTIVE "Specific" The existing Action for suppression pool water level outside limits (Specification 3.7.A. 1) allows no time to restore level. An unanticipated change in suppression pool level would require addressing the cause and aligning the appropriate system to raise or lower the pool level. These activities require some time to accomplish without undo haste. The out-of-service time is based on engineering judgement of the relative risks associated with: 1) the safety significance of the system; 2) the probability of an event requiring the safety function of the system; and 3) the relative risks associated with the plant transient and potential challenge of safety systems experienced by requiring a plant shutdown. Upon further review, and discussion with the NRC Staff, during the development of the BWR Standard Technical Specifications, NUREG 1433, a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> restoration allowance was determined to be appropriate.

BFN-UNITS 1, 2, 5 3 Revision 0 PAGE

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.2.2 - SUPPRESSION POOL MATER LEVEL L2 Per CTS, if suppression pool water level is not maintained within limits, the Specification is violated and in accordance with TS 1.0.C.l the plant must be placed in Hot Standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in Cold Shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> unless suppression pool water level is restored. This provides actions for circumstances not directly provided for in the specifications and where occurrence would violate the intent of the specification. The BFN ISTS provides Action within the Specification which could be considered less restrictive than CTS.

Action B allows 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to be in MODE 3 (Hot Shutdown) and 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> to be in MODE 4 (Cold Shutdown). The proposed Action is considered less restrictive since 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is allowed to place the unit in Hot Shutdown versus the 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowed to place the unit in Hot Standby per CTS.

BFN-UNITS 1, 2, 5 3 Revision 0

4 UNIT I CURRENT TECHNICAL SPECIFICATION MARKUP ra

ent 6oc6~>3

~3.b Thc RHRS shall be OPERABLE 8. l. a. Simulated Once tic 'utoma Operating (1) PRIOR TO STARTUP Ac tua tion Cycle from a COLD Test CONDITION; or

b. Pump OPERA- Pcr Rpfh mbi lily (2) when there is irradiated fuel in BILITY 'pecificatio 1.0.MM the reactor vessel and when the reactor C~ Motor Opera- Per vessel pressure is ted 'valve Specification greater than OPERABILITY 1.0.MM atmospheric, except as specified in d. Pump Flow Once/3 Specifications 3.5.B.2, Rate months through 3.5.B.7.

e~ Test Check Pcr Valve Specification 1.O.MM Verify that Once/Mont each valve (manual,, power-operated, or automatic) in the SW GuS+IPicah'o~ Qgggg. injection flow-kr gpH lsd path that is not locked, sealed, or otherwise secured in posi-tion, is in its correct position.

8~ Verify LPCI Once/Month subsystem cross-maticc tie valve is closed ~

removed from power valve operator.

Low pressure coolant injection Except that an (LPCI) may bc considered OPERABLE automatic valve during alignment and operation capable of auto-for shutdown cooling with reactor return to i ts steam dome pressure less than ECCS position when 105 psig in HOT SHUTDOWN, if an ECCS signal is capable of being manually present may be in realigned and not otherwise a position for another inoperablc. mode of operation.

BFN 3.5/4.5~ AMENDMENT NO. 2 04 Unit 1 PAGP-k OP'I

4

.2.3 AUG 02 1989 If one RHR pump (containment cooling mode) or associated heat exchanger is inoperable, Action/ the reactor may remain in operation for a period not to exceed 30 days provided the remaining RHR pumps (containment cooling mode) See Sushi<'~hboA~ Ck~n)c5 and associated heat exchanger and diesel W 8~hi I575 3,g,>

enera ors d a access paths of the RHRS (containment cooling mode) are OPERABLE.

JC1 loni 8

6. If tvo RHR pumps (containment a t ona cooling mode) or associated heat exchangers are inoperable, the reactor may Sk'g s.z.z.

remain in operation for a i period not to exceed 7 days ~R a.I..Z,p,>

provided the remaining RHR pumps (containment cooling mode), the a ciated heat exchangers iesel generate s all access pa of the RHRS (containment cooling mode) are OPERABLE.

(~p If tvo access paths of the RHRS (containment cooling mode) for each phase of the mo dr@we Se'< gus~'fi'cab'on sup'pression chamber s rays and suppress on pool cool ng) CQ+~ ~ f3PA ISIS are not OPERABLE, the unit 3.4.2.9 + 3.L,w.s may remain in operation for a period not to exceed 7 days provided at least one path for each phase of the mode remains OPERABLE.

t ~oPos~d ACgtOg C BFH 3.5/4.5-6 Unit l

0

8. If Specifications 3.5.B.1 ce

/l.77onl through 3.5.B.7 are not met, uninitiated an orderly shutdown shall be and the reactor 847 s~p

~sftlous shall be laced in the COLD SHUTDOWN CONDITION

~ em~> within hours.

and, Bc When the reac or vesse 9. When the reactor vessel pressure is atmospheric and prcssure is atmospheric, irradiated fuel is in the the RHR pumps and valves reactor vessel, at least one that are required to be RHR loop with two pumps or two OPERABLE shall be loops with one pump per loop demonstrated to be OPERABLE shall bc OPERABLE. The per Specification I.O.MM.

diesel generators pumps'ssociated must also be OPERABLE. Low prcssure coolant injection (LPCI) may bc considered OPERABLE during alignment and operation for shutdown cooling, if capable of being manually realigned and not otherwisc inoperable.

10. If the conditions of 10. No additional surveillance Specification 3.5.A.5 are met, required.

LPCI and containmcnt cooling are not required.

When there is irradiated fuel 11. The RHR pumps on the in the reactor and the reactor adjacent units which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall bc.demonstrated to be associated heat exchangers and OPERABLE per Specification valves on an adjacent unit 1.0.MN when the cross-must be OPERABLE and capable connect capability of supplying cross-connect is required.

capability except as specified in Specification 3.5.B.12 belo~. (Note: Because cross- +c Uus&&aago~ W C~g~

connect capability is not a short-term requirement, a

~ BF'9 ls rs 8.S.) y ~~.~

component is not considered inoperablc if cross-connect capability can be restored to service within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.)

BPN 3.5/4.5-7 ANENOMENt'NO. 20 C Unit l.

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP

ent tainment Coe+hzg+

4t'0 3. Co iQ 3

1. The RHRS shall be OPERABLE a. Simulated Once/

Automatic Operating (1) PRIOR TO STARTUP Actuation Cycle from a COLD CONDITION; or

b. Pump OPERA- Per there is BILITY Specification ApPI;~l till'2) when irradiated fuel in 1.0.MM the reactor vessel and when the reactor C~ Motor Opera- Per vessel pressure is ted valve Specification greater than OPERABILITY l.O.MM atmospheric, except as specified in d. Pump Flow Once/3 Specifications 3.5.B.Z, Rate months through 3.5.B.7.

e. Testable Per Check Specification Valve 1.0.MM Verify that Once/Month each valve (manual, power-operated, or automatic) in the injection flow-path that is not locked sealed or otherwise See. Zuskikeuku~ Eo C~.~ secured in posi-4sr SFM (s~ 3.g.( tion, is in its correct position.

gu Verify LPCI Once/Month subsystem cross-tie valve is closed ~

removed from power valve operator.

f3 Low pressure coolant injection Except that an (LPCI) may be considered OPERABLE automatic valve during alignment and operation capable of auto-for shutdown cooling with reactor matic return to its steam dome pressure less than ECCS position when 105 psig in HOT SHUTDOWN, if an ECCS signal is capable of being manually present may be in realigned and not otherwise a position for another inoperable. mode of operation.

BPÃ 3.5/4.5-4 AMENOMENT KO. 2 28 Unit 2 PAGE OF~

Al ~ AU6 02 58 S st ntainmcnt CooMn~g gQWiog p 5. If one RHR pump (containment cooling mode) or associated rctpl+pccL' heat exchanger is inoperable, thc reactor may remain in operation for a period not to exceed 30 days provided the remaining RHR pumps (containment cooling mode) and associated heat 5ea~~s440;4('.~

exchangers diesc 4 ~PM Is~5 B,.zl enerators all access of the RHRS (containment cooling mode) are OPERABLE.

6~ If tvo RHR pumps (containment ce cooling mode) or associated heat exchangers are inoperable, thc reactor may remain in operation for a (4L SQ 3 t'o.2.3.

~

(

period not to exceed 7 days provided the remaining RHR sg. r.l..z.r.. z pumps (containment cobling mode), thc associated heat cxcha11gersg csc generators access pa of the BHRS (containment cooling mode) are OPERABLE.

7~ If tvo access paths of the RHRS (containment cooling mode) for each phase of thc mode e sprays, S<e T~s7-IF'tcATIafv pop suppression chamber s ra cAAl4G-Eg Fyg and suppression pool cooling) are not OPERABLE, the unit ~ > >ebs may remain in operation for a period not to cxcced 7 days provided at least one path for each phase of the mode remains OPERABLE.

Propose& A<T~ad c BFH 3.s/4.s-6 Unit 2

ANENDMENNO. Ib 9

Cl 3.5.B ent

8. If Specifications 3.5.B.l ce QC jlo+ through 3.5.B.7 are not met, an orderly shutdown shall be

>guest~+ initiated and the reactor shall be placed ia the QO7 OLD SHUTDOWN CONDITION C4C Dln4td within hours. J Z p~ )g.

o 4~~ 96 9 When the reactor vessel 9. When the reactor vessel pressure is atmospheric and pressure is atmospheric, irradiated fuel is in the the RHR pumps and valves reactor vessel, at least one that are required to be RHR loop with two pumps or two OPERABLE shall be loops with one pump per loop demonstrated to be OPERABLE shall be OPERABLE. The per Speci,f ication 1.0.MM.

diesel generators pumps'ssociated must also be OPERABLE. Low pressure coolant injection (LPCI) may be considered OPERABLE during alignment and operation for shutdown cooling, if capable of being manually realigned and not otherwise inoperable.

0. If the conditions of 10. No additional surveillance Specification 3.5.A.5 arc met, required.

LPCI and containment cooling are not required.

When there is irradiated fuel 11. The RHR pumps on the in the reactor and the reactor adjacent units which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall be demonitrated to be associated heat exchangers and OPERABLE per Specification valves on an adjacent unit 1.0.MM when the cross-must be OPERABLE and capable connect capabi.li.ty of supplying cross-connect is re uired.

capability except as specified in Specification 3.5.B.12 below. (Note: Because cross-conncct capability is not a

+ 7I t c A7 (yp I 'Fbg. CHh U~S short-term requirement, a '~~ ~ 5. I 6 R.s. >

component is not considered inoperablc i.f cross-connect capabi.lity can be restored to servi.ce within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.)

3. 5/4. 5-7 AMENOMENT RU 2 23

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

SPzc, P 3 6.2.3 LCa g.(.2+3

1. The RHRS shall be OPERABLE 8. l. a. Simula ted Once/

Automa tie Operating (1) PRIOR TO STARTUP Ac tua t ion Cycle.

from a COLD Test CONDITION'r b Pump. OPERA- Per kyUca b;);yy (2) when there is BILITY Specification irradiated fuel in 1.0.MM the reactor vessel and when the reactor c. Motor Opera- Per vessel pressure is ,ted valve Specificatio greater than OPERABILITY 1.0.MM atmospheric, except as specified in d Pump Flow Once/3 Specifications 3.5.B.2, Rate months through 3.5.B.7.

e~ Testable Per Check Specification Va).ve 1.0.MM Verify that Once/Month each valve (manual, power-operated, or automatic) in the injection flow-path that is not

~K 5% S'can o locked, sealed,

~"8 > 4'~ Bl=e )spy 3,5

( or otherwise secured in posi-tion, ig in its correct. position.

Verify LPCI Once/Month subsystem cross-tie valve is closed ~

removed from power valve operator.

Low pressure coolant injection Except that an (LPCI) may be considered OPERABLE automatic valve during alignment and operation capable of auto-

'for shutdown cooling with reactor matic return to its steam dome pressure less than ECCS position when 105 psig in HOT SHUTDOWN, if an ECCS signal is capable of being manually present may be in realigned and not otherwise a position for another inoperable. ode of operation BFN 3. 5/4. 5-4 em~~er e. z 77 Unit 3 PAGE ~ OF~

AUB 02 1988 5 ~ If one RHR pump (containmcnt Qpl cooling mode) or associated heat exchanger is inoperable, BQjon P the reactor may remain in operation for a period not to exceed 30 days provided the rcmainiag RHR pumps (containment cooliag mode) aad associated heat exchanger diesel

~+

&C 54s M'cnMn + ~~g ISIS g,g,t SION generators all access pa o the RHRS (contaiamcat cooling mode) are OPERABLE.

ocHo~ 8 6~ If tvo RHR pumps (containment cooliag mode) or associated heat cxchaagcrs are inoyerable, the reactor may remain in operation for a aM sRz.r,.z.z, yeriod not to exceed 7 days SR S.b,g.p. m provided the rcmainiag RHR I

yes (contaiamcnt cooling mode), the associated heat exchaag era ese g erators all access pa of the RHRS (containment cooling mode) are OPERABLE.

7~ If tvo access paths of the RHRS (coataiament cooling mode) for each phase of the mode e 1 spra suppression chamber sprays 5K ~g~ { ic~ n QQ. Chgc5, ~

aut suppress oa poo cooling) ~~~ )Sent Z.<.a.q m Z.e.a,s are not OPERABLE, the unit may remain in operation for a yeriod not to cxcecd 7 days provided at least onc path for each phase of the mode remains OPERABLE.

rope/ QQo rl J

BF5 3.5/4.5-6 Unit 3 NENMNTNO. SOO

3.5.B (

ontainm t inment oo xng

8. If Specifications 3.5.B.1 8. nc through 3.5.B.7 are not met, Rh'on p orderly shutdown shall be initiated and the reactor shall bc lace in the HOT Stlut~d S WN CONDITION

&4Dif>owl a4 ~ithin lghe s 3C, hours. Z

9. When the reac or vesse 9. When the reactor vessel pressure is atmospheric and pressure is atmospheric, irradiated fuel is in the the RHR pumps and valves reactor vessel, at least one" that are required to be RHR loop <<ith two pumps or two OPERABLE shall be loops with one pump per loop demonstrated to be shall be OPERABLE. The OPERABLE per diesel generators pumps'ssociated Specification 1.0.MM.

must also be OPERABLE. Low pressure coolant injection (LPCI) may bc considered OPERABLE during alignment and operation for shutdown cooling, if capable of being manually rcaligncd and not otherwise inoperable.

0. If the conditions of 10. No additional surveillance Specification 3.5.A.5 are met, required.

LPCI and containment cooling are not required.

When there is irradiated fuel 11. The B and D RHR pumps on in the reactor and the reactor unit 2 which supply is not in thc COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall be demonstrated to associated heat exchangers and be OPERABLE per valves. on an adjacent unit Specif ication 1.0.MM when must be OPERABLE and capable the cross-connect of supplying cross-connect capability is required.

capability except as specified in Specification 3.5.B.12 below. (Note: Because cross-conncct capability is not a 5~4 ~usga'azfit)n 4( chgwgcc short-term requirement, a @'Pg tSq S s.S.I g3.g.~

component is not considered inoperablc if cross-connect capability can be restored to service within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.)

BFN 3. 5/4. 5-7 AMENDMENT NO. y. 77 Unit 3 or-pp,GE

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.2.3 - RHR SUPPRESSION POOL COOLING ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BMR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

t TECHNICAL CHANGES Ml

- MORE RESTRICTIVE Surveillance Requirements (SR 3.6.2.3. 1 and 3.6.2.3.2) have been added to ensure that the correct valve lineup for the RHR suppression pool cooling subsystems is maintained and RHR pump testing is performed to ensure the RHR suppression pool cooling subsystems remain capable of providing the overall DBA suppression pool cooling requirement. This change is consistent with NUREG-1433.

M2 CTS 3.5.B.8 requires an orderly shutdown be initiated.and the reactor to be in the Cold Shutdown Condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when required RHR suppression pool cooling subsystems are inoperable. Proposed Action 0 will require the plant be in MODE 3 (Hot Shutdown Condition) in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 (Cold Shutdown Condition) in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The addition of this intermediate step to the Cold Shutdown Condition is considered more restrictive since CTS does not require any action to have taken place within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. 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 safety systems.

BFN-UNITS 1, 2, 5 3 Revision 0

Cl JUSTIFICATION FOR CHANGES BFN ISTS 3.6.2.3 - RHR SUPPRESSION POOL COOLING TECHNICAL CHANGES - LESS RESTRICTIVE Ll Proposed ACTION C will allow 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to restore required RHR suppression pool cooling subsystems to operable status prior to initiating a shutdown. The proposed 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time provides some time to restore the required subsystems to Operable status, yet is short enough that operating an additional 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is not risk significant. Only 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is allowed since their is a substantial loss'f the 'primary containment bypass leakage mitigation function. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> restoration time is considered acceptable due to the low probability of a DBA and because alternative methods to remove decay heat from the primary containment are still available. In addition, if the required subsystem(s) are restored to Operable status prior to the expiration of the 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, a unit shutdown is averted. Thus, the potential of a unit scram occur ring while shutting the unit down, which then could result in a need for a subsystem when it is inoperable, has been decreased.

L2 The time to reach NODE 4, Cold Shutdown, has been extended from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This provides the necessary time to shut down and cool down the plant in a controlled and orderly manner that is within the capabilities of the unit, assuming the minimum required equipment is OPERABLE. This extra time reduces the potential for a unit upset that could challenge safety systems. In addition, a new (more restrictive) requirement to be in NODE 3 (Hot Sh'utdown) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been added. These times are consistent with the BWR Standard Technical Specifications, NUREG 1433.

BFN-UNITS 1; 2, 5 3 Revision 0

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP pAGE

E III

nt

~ockk~

LCO ZiC ~ 2ig l 1. The RHRS shall be OPERABLE 8. I. a. Simula ted Once/

Automatic Operating (1) PRIOR TO STARTUP Ac tua tion Cycle from a COLD Tes t CONDITION; or

b. Pump OPERA- Per (2) when there is BILITY Specification

~/'f licobilil-) irradiated fuel in 1.0.MM the reactor vessel and when the reactor C ~ Motor Opera- Per vessel pressure is ted 'valve Specification greater than OPERABILITY 1.0.MM atmospheric, except as specified in d~ Pump Flow Once/3 Specifications 3.5.B.2, Rate months through 3.5.B.7.

Test Check Per Valve Specification 1.0.MM Verify that Once/Month each valve (manual, power-operated, or 5c'e SK5+0'+ on Q~ggc automatic) in the injection flow-8PIJ lsd 3,g, J path that is not locked, sealed, or otherwise secured in posi-tion, is in its correct position.

Verify LPCI Once/Month subsystem cross-tie valve is closed gaul power removed from valve operator.

Low- pressure coolant injection

• Except that an (LPCI) may be considered OPERABLE automatic valve during alignment and operation capable of auto-for shutdown cooling with reactor matic return to its steam dome pressure less than ECCS position when 105 psig in HOT SHUTDOWN, if an ECCS signal is capable of being manually present may be in realigned and not otherwise a position for another inoperable. mode of operation.

BFN 3.5/4.5-4 AMNOuENT HO.

Unit 1 pp 20'ATE 5

AUG 02 tggg 3.5.B ova S t 4.5.B. s ua ca e ova S st

~g~

Cooling)

(LPCI and Containment Qg~ (LPCI and Containment Cooling) 4.5.B.1 (cont'd)

2. With the reactor vessel Each LPCI pump shall deliver pressure less than 105 psig, 9000 gpm against an indicated the RHRS may be removed system pressure of 125 psig.

from service (except that tvo Tvo LPCI pumps in the same RHR pumps-containment cooling loop shall deliver 12000 gpm mode and associated heat against an indicated system exchangers must remain pressure of 250 sig.

OPERABLE) for a period not to excccd 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> vhile 2. An r tes on the ryvel being drained of SR 3'L,z.g,z and torus headers an nozzles suppression chamber quality shall be conducted once/5 vater and filled vith years. v ter tes c primary coolant quality form on thc oru he cr vater provided that during LR) in ieu o th air st.

cooldown tvo loops vith one pump per loop or one loop vith tvo pumps, and associated diesel Se< 3~qqi~~~ g, g~~~

generators, in the core ~ B~e icy',<.z.S spray system arc OPERABLE.

3. If one RHR pump (LPCI mode) 3. Ho additional surveillance is inoperable, the reactor required.

may remain in operation for a period not to exceed 7 days provided the remaining RHR pumps (LPCI mode) and both access paths of thc RHRS (LPCI mode) and thc CSS and thc diesel generators remain OPERABLE.

4. If mqr 2 RHR pumps (LPCI 4. Ho additional surveillance mode) become inoperable, thc required.

reactor shall be placed in the COLD SHDTDOWH COHDITIOH vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Sc~ Z~sw~

Bee ~ sag BPH 3.5/4.5-5 PAGE ~ ~'

P '"

Unit 1 QIENOMENT NO. 16 9

QeciQrcqg~ p.g,2 y AUG 02 t989

5. If one RHR pump (containment cooling mode) or associated heat exchanger is inoperablc, the reactor may remain in operation for a period not. to Bono/V exceed 30 days provided the remaining RHR pumps (containment cooling mode) and associated hea cxchangers and diese enera or and all access

<<<a SWAah' C~

paths of the RHRS f r Qppf )5y5 3 (containment cooling mode) are OPERABLE.

6. If tvo RHR pumps (containment cooling mode) or associated heat exchangers are inoperable, the reactor may Add s'g g.

remain in operation for a period not to exceed 7 days 8'l.n~e provided the remaining RHR yumys (containment cooling mode), the associated heat exchangers, iese 8 enera and all access pa of the RHRS (containmcnt cooling mode) are OPERABLE.

7~ If tvo access paths of the RERS (containmcnt cooling mode) for each phase of the mode dryve prays ress on er sprays, sad ress on oo cooling Sec y<s+5(~agon Sac Changes am not E LE, thc un 4 ~ N=o I5T's, v.a.~.3 +3,(,z,5 msp'emain in operation for a period not to exceed 7 days provided at least one path for each yhase of thc mode remains OPERABLE.

LI ~&58k +T (pg Q BFE 3.5/4.5-6 Unit 1 NENDMENTNO. 16 9

nt nment

8. If Specifications 3.5.B.1 through 3.5.B.7 are not met, an orderly shutdown shall be

~a~. Nz kTJ0N initiated and the reactor D shall be placed in the >n +he QT SHQYSOM COLD SH WN CONDITION &no>p'ion) )g within ho s.

C.2,

9. When ac or vessel When the reactor vessel pressure is atmospheric and pressure is atmospheric, irradiated fuel is in the the RHR pumps and valves reactor vessel, at least one that are required to be RHR loop with two pumps or two OPERABLE shall be loops with one pump per loop demonstrated to be OPERABLE shall be OPERABLE. Thc per Speci.fication 1.0.MM.

diesel generators pumps'ssociated must also be OPERABLE. Low pressure coolant injection may be considered 'LPCI)

OPERABLE during alignment and operation for shutdown cooling, if capable of being manually realigned and not otherwise inoperable.

0. If the condi.tions of 10. No additional surveillance Specification 3.5.A.5 are met, required.

LPCI and containment cooling are not required.

When there is irradiated fuel 11. The RHR pumps on the in the reactor and the reactor adjacent units which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION,' RHR pumps and shall be. demonstrated to be associated heat exchangers and OPERABLE per Specification valves on an adjacent unit 1.0.MN when the cross-must be OPERABLE and capable connect capability of supplying cross-connect is required.

apability except hours' as specified in Specification 3.5.B.12 below. (Note: Because cross- 5<< 5'w'0'ca4og connect capability is not a 0< 5FQ ISTs z.s,l short-term requirement, a lI g > ~

component is not considered inoperable if cross-connect capability can be restored to service within 5 )

BFN 3.5/4.5-7 'AMENDMENT NO. 204 Unit 1

UNIT 2 CURRENT TECHNICAL SP ECIFICATION MARKUP

3.5.B 4.5.B on ax ent nt

~iraq~

LCo $.42.Lt Bc'?b~)

1. The RHRS shall be OPERABLE 1. a. Simulated Once/

Automatic Operating (1) PRIOR TO STARTUP Actuation Cycle from a COLD Test CONDITION'r

b. Pump OPERA- Per a.gpss;~4 l;4p (2) when there is BILITY Specification irradiated fuel in 1.0.MM the reactor vessel and when the reactor Co Motor Opera- Per vessel pressure is ted valve Specif ication greater than OPERABILITY 1.0.MM atmospheric, except as specified in d. Pump Flow Once/3 Specifications 3.5.B.2, Rate months through 3.5.B.7.

e. Testable Per Check Specification Valve 1.0.MM Verify that Once/Month each valve (manual, power>>

operated, or automatic) in the injection flow-path that is not See.xuSC(f'~]4 locked, sealed, g,~.I or otherwise

%~ EFW lSrr 3.S: I secured in posi tion, is in its correct position.

ge Verify LPCI Once/Month subsystem cross-tie valve is closed ~

removed from power valve operator.

Low prcssure coolant injection Except that an (LPCI) may be considered OPERABLE automatic valve during alignment and operation capable of auto-for shutdown cooling with reactor matic return to its steam dome pressure less than ECCS position when 105 psig in HOT SHUTDOWN, if an ECCS signal is capable of being manually present may be in realigned and not otherwise a position for another inoperable. ode of oper tio BFN 3.5/4.5~ AMENOMBfTRo. 22S Unit 2

t 3.5.B

~~

R du Cooling) 2.

v With the reactor vessel S

(LPCI and Containment te 4.5.B. s Q@ESS.

ua Cooling) 4.5.B.1 (cont'd) at e ova Each LPCZ pump shall deliver AUG S

(LPCZ and Containment 02 t88g t

pressure less than 105 psig, 9000 gpm against an indicated the RHRS .may be removed system pressure of 125 psig.

from service (except that tvo Tvo LPCI pumps in the same RHR pumps-containment cooling loop shall deliver 12000 gpm mode and associated heat against an indicated system cxchangers must remain pressure of 250 psig.

OPERABLE) for a period not

,to exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> vhile 2. An t s an th dryvel being drained of Sg ~~ > ~> an torus headers an nozzles suppression chamber quality shall be conducted once/5 vater and filled vith years. water test may e coalant quality 'rimary per cd on 6 total heads water provided that during in lie of the Sir te caoldovn tvo laops vith one pump per loop or one loop with tvo pumps, and associated diesel generators, in the core spray system are OPEUSLZ.

3. Zf one RHR pump (LPCI mode) 3. o a onal surveillance is inoperable, the reactor required.

may remain in operation for a period not to exceed 7 days provided the remaining RHR pumps (LPCI mode) and both access paths of the RHRS (LPCZ mode) and the CSS and the diesel generators remain OPERABLE

4. If any 2 RHR pumps (LPCI 4. Ho additional survcillancc mode) bccomc inoperable, the required.

reactor shall be placed in the COLD SHDTDOWH COHDZTIOH vithin 24 hours.

Qj? 48$ /'licollpa gi g4~<+

NFL ICW 3.g.(

3. 5/4. 5-5 AMENDMENTNO. 16 9

Al S If one RHR pump (containment cooling mode) or associated rgsp~.

heat ezchanger is inoperable, the reactor may remain in operation for a period not to Ac<(ad ezceed 30 days provided the reams~ RHR pumps (containment cooling mode) and associated heat exchangers and diese +~ ~t g4 0(cqfi 0 n 4r generators and all access 40( Ep/LJ /5~

paths of the RHRS (containment cooling mode) are OPERhBLE.

If two RHR pumps (containment cooling mode) or associated

'eat exc8xangers are inoperable, the reactor Ado', SR'.C.a.y /

~ P" (

in operation for a map'emain ~

~

period not to exceed 7 days provided the remaining RHR pumps (containment cooling mods) ~ the associated heat exchangers, diesel enerato s aQ access Ac%(od paths of the RHRS

& (containment cooling mode) are OPEELBLE.

70 If two access paths of the RHRS (containment cooling mode) for each hase of the mode dzpvell sprays suppress on chamber sprays, ress on 5&V ~$ 7 IFJCPSTsdAJ PbR CHAhlk~

are not OPERhBLE, the unit <<~ BFN /sr',@ p 3 pg gg,~

may remain in operation for a period not to exceed 7 days provided at least one path for each phase of the made remains OPZMBLE.

P~q~sM Ace>OW ~

BF5 5/4.S-6 PAGE 3

Unit 2

AM@WarrNO. re e

~A) inment inment

e. If Specifications 3.5.B.1 through 3.5.B.7 are not met, do A('(ohl an orderly shutdown shall be initiated and the reactor shall be placed n e pl,e Po~ S(lu77N~hl COLD SHUTDOWN CONDITION CO~ O(7 Sahl ~ Q(B~rS W~d within hours L.Z $4 ac or vessel 9. When the reactor vesse pressure is atmospheric and pressure is atmospheric, irradiated fuel is in the the RHR pumps and valves reactor vessel, at least one that are required to be RHR loop with two pumps or two OPERABLE shall be loops with one pump per loop demonstrated to be OPERABLE shall bc OPERABLE. The per Speci.fication 1.0.MM.

diesel generators pumps'ssociated must also be OPERABLE. Low prcssure coolant injection (LPCI) may be considered OPERABLE during alignment and operation for shutdown cooling, if capable of being manually realigned and not otherwise inoperable.

0. If the conditions of 10. No additional surveillance Specification 3.5.A.S are met, required.

LPCI and containment cooling are not required.

When there is irradiated fuel 11. The RHR pumps on the in the reactor and the reactor adjacent units which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall bc demonstrated to be associated heat exchangers and OPERABLE per Specification valves on an adjacent unit 1.0.MM when the cross-must be OPERABLE and capable connect capability of supplying cross-connect is required.

capability except as specified in Specification 3.5.B.12 below. (Note: Because cross- See v.us AC cako m ('~~,

connect capability is not a short-term requirement, a component is not considered 8(c'hl IS ~ 3'g ( g gS. Z.

inoperable if cross-connect capabi.lity can be restored to service within 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.)

BFN .5/4.5-7 AMENDMEMT m. 2 23

0' UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

Cl 4.5.B ent ent

~CO 3 4 1. <l be OPERABLE 0. l.

o o o

1. The RHRS shall a. Simulated Once/

Automatic Operating (1) PRIOR TO STARTUP Ac tuation Cycle from a COLD Tes t CONDITION'r

b. Pump OPERA- Per

~PfLECab,'f.Q (2) when there is BILITY Specification irradiated fuel in 1.0.MM the reactor vessel and when the reactor C~ Motor Opera- Per vessel pressure is ted valve Specification greater than OPERABILITY 1.0.MM atmospheric, except as specified in d. Pump Flow Once/3 Speci.fications 3.5.B.2, Rate months hrough 3.5.B.7.

e ~ Testable Per Check Specification Valve l.O.MM Verify that Once/Month each valve (manual, power-operated, or automatic) in the injection flow-path that is not locked, sealed, or otherwise

~ SwS+Ac4un secured in posi-4< 8 apl )5 TS y, g ) tion, ig in its correct position.

go Verify LPCI Once/Month subsystem cross-tie valve is closed ~

removed from power valve operator.

Low pressure coolant injection Except that an (LPCI) may be considered OPERABLE automatic valve during alignment'nd operation capable of auto-

'for shutdown cooling with reactor matic return to its steam dome pressure less than ECCS position when 105 psig in HOT SHUTDOWN, if an ECCS signal is in capable of being manually present may be realigned and not otherwise a position for another inoperable. mode of operation.

BFN Unit

3. 5/4. 5-4 N@DMENr go; I 77 3

' .(o.2 9

~

AUB 02 I88S 4.5.B 4.5.B.1 (cont'd)

2. Mith the reactor vessel Each LPCI pump shall deliver pressure less than 105 psig, 9000 gpa against an indicated the RHRS may be removed system pressure of 125 psig.

from service (except that tvo Two LPCI pumps in the same RHR pumps-containment cooling loop shall deliver 12000 gpm mode aad associated heat against an indicated system cxchangers must remain pressure of 250 psig.

OPE)ULBLE) for a period not to exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> vhilc 2.

i hn ir test on thc cl being drained of SRS.c.z. torus eadcrs and nozzle suppression chamber quality shall be conducted once/5 vater and filled vith years. k v st map c primary coolant quality erform oa t h$adc vater provided that during lieu th air st.

cooldovn tvo loops with one Eussy'iF:iW'r pump per loop or one loop vith tvo pumps, and associated diesel Sc< r generators, ia the core +rihtsys44 BR'STS Zi4 eX,5 spray system are OPERkBIS.

3i If oae RHR pump (LPCI mode) 3. Eo additional surveillance is inoperable, the reactor required.

may remain ia operation for a period not to exceed 7 days provided the rcmaixdLag RHR pumps (LPCI mode) aad both access paths of the RHRS (LPCI mole) and the CSS and the diesel generators rcmaia OPERhBLE o If any become 2 RHR pumps (LPCI inoperable, the

4. Eo additional surveillance required.

Node) reactor shall be placed in the COLD SHOTDOMH COHDITION within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

5<8 34s~f:~~'o<4 Ch ~s 4r B~g lS~ 3.5 I BFS Unit 3 3.5/4.5-5

)~*r ~ "XC 5

a o NENDMENTNO. ~

n 3.4.2. AUB 0 2 1988 4.5 B.

5. If one RHR pump (containmcnt 5.

cooling mole) or associated heat exchanger is inoperable, the reactor may remain in operation for a period not to exceed 30 days provided the remaining RHR pumps (containment. cooling mode) and associated he cxchcuwcr and diesel Sc'< Du s~ Pea h'o n Qr Ai 8PN C~~

lST5 P.y. i generators and all access pa of the RHRS (containment cooling mode) e OPEBkBIS 6~ If tvo c'aoling RHR pumps (containmcnt mode) or assaciatcd heat cxchangers are Wt inoperable, the reactor may Rdd sR s.c,z,q,i remain in operation for a period not to exceed 7 days provided the rcmaQdng RHR 4+n pumps (containmcnt cooling 8 mode), the associated heat cxchangera ese genera ors, and all access pa o e RHRS (cantainmcnt cooling mode) are OPElhLBLS.

7~ If tvo access paths of the

'(g RHRS (cantainmcnt cooling made) for each e of the a+de ell a r ression chamber sprays, ress on oo o c~ 3wswf 'azgo~ g,( g~~~

are nat OPERhBLE, the unit ISIS g,g,Z,~~ > < z >

may remain in operation for a period not to exceed 7 days provided at least one path for each phase of the mode remains OPERABLE.

f~w~z Zy,c pAcE OF5 BF5 3 '/4 '-6 Unit 3 AMMMENTNO. 1o o

3.5.B 4.5. B 8- If Specifications 3.5.B.1 through 3.5.B.7 are not met, ~kTCtk o an orderly shutdown shall be

. initiated and th eactor shall be place in the fn He Q)QSHuygavp4 Co+DiTie COLD SHUTDOWN CONDITION I h IP boating AhD within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3 When actor vessel 9. When the reactor vessel pressure is atmospheric and pressure is atmospheric irradiated fuel is in the the RHR pumps and valve reactor vessel, at least one that are required to be RHR loop with two pumps or two OPERABLE shall be loops with one pump per loop demonstrated to be shall be OPERABLE. The OPERABLE per diesel generators pumps'ssociated Specif ication 1.0.MM.

must also be OPERABLE. Low pressure coolant injection (LPCI) may bc considered OPERABLE during alignment and operation .for shutdown cooling, if capable of being manually realigned and not otherwise inoperablc.

0. If the conditions of 10. No additional surveillance Specification 3.5.A.5 are met, required.

LPCI and containment cooling arc not required.

When there is irradiated fuel 11'. The B and D RHR pumps on in the reactor and the reactor unit 2 which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall be demonstrated to associated heat exchangers and be OPERABLE per valves on an adjacent unit Specification 1.0.MM when must be OPERABLE and capable the cross-connect of supplying cross-connect capability is required.

.capability except as specified in Specification 3.5.B.12 below. (Note: Because cross-connect capability is not a

~

gl ELVA'PIcgh'oQ gr gfel~cf ggjg ]$ 'fg short-term requirement, a component is not considered inoperable if cross-connect capability can be restored to service within 5 hours.

BPN 3.5/4.5-7 AMENOMEHT MO. I 77 Unit 3 PAGE~Ci

t BFN ISTS ADMINISTRATIVE CHANGES Al JUSTIFICATION 3.6.2.4 -

FOR CHANGES RHR SUPPRESSION POOL SPRAY Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

TECHNICAL CHANGES - NORE RESTRICTIVE Surveillance Requirement (SR 3.6.2.4.1) has been added to ensure that the correct valve lineup for the RHR suppression pool spray subsystems is maintained. This ensures that the RHR suppression pool spray subsystems remain capable of providing the overall DBA suppression pool spray requirement. This change is consistent with NUREG-1433.

H2 CTS 3.5.B.8 requires an orderly shutdown be initiated and the reactor to be in the Cold Shutdown Condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when required RHR suppression pool spray subsystems are inoperable. Proposed Action 0 will require the plant be in NODE 3 (Hot Shutdown Condition) in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 (Cold Shutdown Condition) in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The addition of this intermediate step to the Cold Shutdown Condition is considered more restrictive since CTS does not require any action to have taken place within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. 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 safety systems.

BFN-UNITS 1, 2, 8L 3 Revision 0

0 0

JUSTIFICATION FOR CHANGES ISTS 3.6.2.4 - RHR SUPPRESSION

'FN POOL SPRAY TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" LA1 Details of the methods of, performing surveillance test requirements have been relocated to the Bases and procedures. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in proposed BFN ISTS Section 5.0 and changes to the procedures will be controlled by the licensee controlled programs.

"Specific" Ll Proposed ACTION C will allow 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to restore required RHR suppression pool spray subsystems to operable status prior to initiating a shutdown.

The proposed 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time provides some time to restore the required subsystems to Operable status, yet is short enough that operating an additional 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is not risk significant. Only 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is allowed since their is a substantial'oss of the primary containment bypass leakage mitigation function. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> restoration time is considered acceptable due to the low probability of a DBA and because alternative methods to remove decay heat from the primary containment are still available. In addition, if the required subsystem(s) are restored to Operable status prior to the expiration of the 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, a unit shutdown is averted. Thus, the potential of a unit scram occur ring while shutting the unit down, which then could result in a need for a subsystem when it is inoperable, has been decreased.

L2 The time to reach NODE 4, Cold Shutdown has been extended from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This provides the necessary time to shut down and cool down the plant in a controlled and orderly manner that is within the capabilities of the unit, assuming the minimum required equipment is OPERABLE. This extra time reduces the potential for a unit upset that could challenge safety systems. In addition, a new (more restrictive) requirement to be in NODE 3 (Hot Shutdown) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been added. These times are consistent with the BWR Standard Technical Specifications, NUREG 1433.

BFN-UNITS, 1, 2, 5 3 Revision 0 PAGE~OF~

0 UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

0

~ ~

inment an ent

1. The RHRS shall be OPERABLE 8. ~ ao Simulated Once/

'utomatic Operating (1) PRIOR TO STARTUP Actuation Cycle from a COLD Test CONDITION or

b. Pump OPERA- Per

~lfl'Qh;l,g (2) when there is BILITY Specification irradiated fuel in 1.0.MM the reactor vessel and when the reactor C ~ Motor Opera- Per vessel pressure is ted 'valve Specification greater than OPERABILITY 1.0.MM atmospheric, except as specified in d~ Pump Flow Once/3 Specifications 3.5.B.2, Rate months through 3.5.B.7.

e. Test Check Per Valve Specification 1.O.MM Verify that Once/Month 0

each valve (manual, power-operated, or 5'ee T~s&l~on 4r automatic) in the

~'<

injection f 1ow-path that is not 35,( locked, sealed, or otherwise secured in posi>>

'tion is ln its correct position.

ge Verify LPCI Once/Month subsystem cross-tie valve is closed azLd power removed from valve operator.

Low pressure coolant injection E xcept that an (LPCI) may be considered OPERABLE automatic valve l during alignment and operation capable of auto-for shutdown cooling with reactor matic return to its steam dome pressure less than ECCS position when 105 psig in HOT SHUTDOWN, if an ECCS signal is capable of being manually present may be in realigned and not otherwise a position for another inoperable. mode of operation.

BFN 3.5/4.5-4 AMENDMENT go. 2Pg Unit 1 PAGE

0 S c.4icn AUG 02 1989 3.5.B ova S st 4.5.B. s dua ea e ova S tern Qg~ (LPCI and Containment Qgg~ (LPCI and Containment Cooling) Cooling) 4.5.B.1 (cont'd)

2. Mith thc reactor vessel Each LPCI pump shall deliver pressure less than 105 psig, 9000 gpm against an indicated the RHRS may bc removed system pressure of 125 psig.

from service (except that tvo Tvo LPCI pumps in the same

~

RHR pumps-containment cooling loop shall deliver 12000 gpm mode and, associated heat against an indicated system exchangers must remain prcssure of 250 psig.

OPERABLE) for a period not to exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> vhile 2. An r e on the drywell being drained of Sc a'.a.g,g. g orus headers and nozzles suppression chamber quality e conducted once/5 vatcr and filled vith years. vater test may be primary coolant quality er ormed on the torus header.

vater provided that during in lieu of the air test.

cooldovn tvo loops vith one pump per loop or one loop vith tvo pumps, and associated diesel

~conge~~~Q~Q'un 4,i gl-~

Po r IS~s generators, in the core spray system are OPERABLE.

3. If one RHR pump (LPCI mode) 3. Ho additional surveillanc is inoperable, the reactor r cquir ed.

may remain in operation for a period not to exceed 7 days provided the remaining RER pumps (LPCI mode) and both access paths of the RHRS (LPCI mode) and the CSS and the diesel generators remain OPERABLE.

4. If any 2 RHR pumps (LPCI 4. Ho additional surveillanc mode) become inoperable, thc required.

reactor shall be placed in the COLD SHUTDOWH COHDITIOH vithin 24 hours. See @wc.+4;cat <~*, g~

+ $<< lSTS S.S,i BFH 3.5/4.5-5 Unit 1 AMENDMENTNO. 16 9

~kwon 9 g,2~

AUG 02 $ 989 te ent ainment

~oIXng)

5. If one RHR pump (containment Qg) . o a ance cooling mode) or associated heat exchanger is inoperable, the reactor may remain in i9C7lorJ operation for a period not to exceed 30 days provided the remaining RHR pumps (containment cooling mode) +~ 3~s+ <~ah'on 4 cgqcs and associated heat exchanger ese b'<6 lsT$ 3.LI enerator and all access paths of the RHRS (containment cooling mode) are OPERABLE.

6. If tvo RHR pumps (containment cooling mode) or associated heat exchangers are inoperable, the reactor may Rg sa s,e, z, s.

remain in operation for a ~

period not to exceed 7 days provided the remaining RHR pumps (containment cooling mode), the asso ted heat exchaagers, d ener and all access paths of the RHRS (containment cooling mode) are OPERABLE.

QAi

7. If tvo access paths of the RHRS (containment cooling mode) for each phase of the mode (dryvell sprays, uppress on e and suppression pool cooling)

~

are no PERABLE, e t may remain in operation for a period not to exceed 7 days provided at least one path for each phase of the mode remains OPERABLE.

fpopgrA RTI o~ <

BFH 3 '/4.5-6 Unit 1 hMENONENT NO. 16 9

nment

8. If Specifications 3.5.B.1 lance through 3.5.B.7 are not mct, an orderly shutdown shall be

~

initiated and the reactor in ~hC H r SHOTOO~N shall be placed in the in 12hrs An/

COLD SHUTDOWN CONDITION within ~~hours. 3S

9. When the reactor vessel 9. When the reactor vessel pressure is atmospheric and pressure is atmospheric, irradiated fuel is in the thc RHR pumps and valves reactor vessel, at least onc that are required to be RHR loop with two pumps or two OPERABLE shall be loops with one pump per loop demonstrated to be OPERABL shall bc OPERABLE. The pcr Specification 1.0.MM.

diesel generators pumps'ssociated must also be OPERABLE. Low pressure coolant injection (LPCI) may be considered OPERABLE during alignment and operat'ion for shutdown cooling, i.f capable of being manually realigned and not otherwise inoperable.

0. If thc conditions of 10. No additional surveillance Specification 3.5.A.5 are met, required.

LPCI and containmcnt cooling are not required.

When there is irradiated fuel 11. The RHR pumps on the in the reactor and the reactor adjacent units which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall be.demonstrated to be associated heat exchangers and OPERABLE per Specification valves on an adjacent unit 1.0.MM when the cross-must bc OPERABLE and capable connect capability of supplying cross-connect is required.

capability except as specified in Specification 3.5.B.12 below. (Note: Because cross-connect capability is not a 5 CuZlkt tip'so%Iud lsi QAwilh short-term requirement, a W GFW lST'S 3'S.l + '3,5.p.

component is not considered inoperable if cross-connect capability can be restored to service within 5 hours.)

BFN 3. 5/4.5-7 AMENDMENT NO. 204 Unit 1 pAGE

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP

5 s.ci4icathien 3.Q.2.g ent ainment

1. The RHRS shall be OPERABLE l. a. Simulated Once/

Automatic Operating (1) PRIOR TO STARTUP Ac tua tion Cycle from a COLD Test CONDITION; or

b. Pump OPERA- Per (2) when there is BILITY Specification irradiated fuel in l.O.MM the reactor vessel and when the reactor C~ Motor Opera- Per vessel pressure is ted valve Specification greater than OPERABILITY l.O.MM atmospheric, except as specified in d. Pump Flow Once/3 Specifications 3.5.B.2, Rate months through 3.5.B.7.

e. Testable Per Check Specification Valve 1.0.MM Verify that Once/Month each valve (manual, power-operated, or automatic) in the injection flow-path that is not locked, sealed, or otherwise secured in posi-tion, is in its correct position.

Verify LPCI Once/Month subsystem cross-tie valve is closed gaul power removed from valve operator.

f$

Low pressure coolant injection Except that an (LPCI) may be considered OPERABLE automatic valve during alignment and operation capable of auto-for shutdown cooling with reactor metic return to its steam dome pressure less than ECCS position when 105 psig in HOT SHUTDOWN, capable of being manually if an ECCS signal is present may be in realigned and not otherwise a position for another inoperable. mode of operation.

BFN 3.5/4.5-4 AMENDMENT RO. 22S Unit 2

5 sf~ceAon QC,25 OH AUG 02 t98G 3.5.B 4.5.B. u Rcmova S st KHRQ, (LPCI and Containmcnt QQ~S (LPC1 and Containment Cooling) Cooling) 4.5.B.1 (cont'd)

2. Pith the reactor vessel Each LPCI pump shall deliver pressure less than 105 psig, -

9000 gpm against an indicated the RHRS may be removed system pressure of 125 psig.

from service (except that tvo Tvo LPCI pumps in the same BHR pumps-containment cooling loop shall deliver 12000 gpm mode and associated heat against an indicated system cxchangers must remain essare of 250 sig.

3PERABLE) for a period not to exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> vhile 5'R

2. Aa n the dryvell being drained of and torus headers and nozzles suppression chamber qaality. S.C.2.S'.2. s e conducted once/5 vater and filled vith years. vater test may b primary coolant quality per ormed on the torus header vater yrovidcd that daring in lieu of the air. test.

"ooldowa tvo loops vith one pump per loop or one loop A'e WdA(Cubo 4" C~Q>S vith tvo yamps, and 4r BF~ is& RC.2.$

associated diesel generators, ia the core spray system are OPERABLE.

3. If one RHR pump (LPCI mode) 3. Ho additional surveillance is inoperablc, the reactor required.

may remain in operation for a period not to exceed  ? days provided the rcmaiaiag RHR pampa (LPCI mode) aad both access paths of the RHRS (LPCI mode) and the CSS and the diesel generators remain OPERABLE

4. If any 2 RHR pamys (LPCI 4. Ho additional surveillance mode) become inoperable, the required.

reactor shall be placed in the COXu SHOTBOmr COHDITIOH vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SIP, WR+fscRL~ 0o~ ~+ 5'tS BI hl ISTIC 3.Q,/

BFH 3.5/4.5-5 PAGE~OF~

Unit 2 AMEMMENTNO. I,6 9

Pl 4~ ~ a Sst aiamcnt 5 ~ If one RHR pamy (containment cooling mode) or associated heat cxchaagcr is inoperable, g(.Z(oa the reactor may remain in A operation for a period not to exceed 30 days provided the renmixxiag RHR yamys (contaiamcnt cooling mode) and associated heat cx ers and diesel cnerato s access paths of the RHRS (containment cooling mode) are OPERABLE.

6~ If tvo RHR yamys (contaiamcnt 0 s cooling mode) or associated

'eat exchaagers are inoperable, the reactor in oyeration for a map'emda period aot to exceed 7 days yrovided the remaining RHR pampa (ccmtaiameat cooling mode), the associated heat dies cnerator 1 access yaths of the RHRS (contaiameat cooling mode) are OPERABLE.

70 If two access paths of the RHRS (containmcat cooliag made) for each phase of the mode (dryvell syra press cm er syrays, +<sf<$~0jflow pop QLgr~~~

and suppression pool cooling gp'hl /57-g are not OPERABIZ, the t 40(

4W 9.d.g.

aalu rennin ia oyeration for a gf period aot to exceed 7 days provided at least one path for each yhase of the mode remains OPERABLE.

TroposM ALTiod C, BFE 3 5/4.5-6 Unit 2

AMNnMan xO. ze 9

Qgi aa n aiament ainmen t COUTin~g

8. If Specifications 3.5.B.1 through 3.5.B.7 are not met, an orderly shutdown shall be initiated and the reactor QZ' shall bc placed ia t e ~ +4<- 8+T $ A'ergot L2.

COLD SH within CONDITION ours.

N'~ ~Z 4c ~ w~cP ea e reactor vessel 9. When thc reactor vessel pressure is atmospheric aad pressure is atmospheric, irradiated fuel is in the the RHR pumps and valves reactor vessel, at least onc that are required to be RHR loop with two pumps or two OPERABLE shall be loops with one pump per loop" demonstrated to bc OPERABLE shall be OPERABLE. Thc per Specification 1.0.MM.

diesel generators pumps'ssociated must also be OPERABLE. Low pressure coolant injection (LPCI) may bc considered OPERABLE during alignment and operation for shutdown cooling, if capable of being manually realigned and not otherwise inoperable.

O If the conditions of 10. No additional surveillance Specification 3.5.A.5 are met, required.

LPCI and containment cooling are not required.

When there is irradiated fuel ll. The RHR pumps on the in the reactor and the reactor adjacent units which supply is not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall be demonstrated to bc associated heat exchangers and OPERABLE per Specification valves on aa adjacent unit 1.0.MM when thc crose-must be OPERABLE and capable connect capability of supplying cross-connect is required.

capability except as specified in Specification 3.5.B.12 below. (Note: Because cross-conaect capability is not a S ~sVIF'~~ r>c4 FoA cls~~ayr short-term requirement, a Pdk sf'< Ism 3 5 ( pg g Z component is not considered inoperable if cross-connect capability can be restored to icrvice within 5 hours.)

BFN 3.5/4.5-7 AMENDMENT HU. 2 23 Unit 2

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

Cl 0

0

3.5.B ent

1. The RHRS shall be OPERABLE 0. ~ a~ Simula ted Once/

Automatic Operating (1) PRIOR TO STARTUP Actuation Cycle from a COLD Test CONDITION; or

b. Pump OPERA- Per (2) when there is BILITY Specification

+1'cab; f;Q irradiated fuel in 1.0.MM the reactor vessel'nd when the reactor C~ Motor Opera- Per vessel pressure is ted valve Specificatio greater than OPERABILITY 1.0.MM atmospheric, except as specified in d. Pump Flow Once/3 Specifications 3.5.B.2, Rate months through 3.5.B.7.

e~ Testable Per Check Specification Valve 1.0.MM Veri,fy that Once/Month each valve (manual, power-operated, or automatic) in the injection flow-path that is not locked, sealed, or otherwise secured in posi-ew wu>e,lsd% n *r chn~er tion, ig in its 4u. ~ iSV5 g,g, I correct position.

Veri fy LPCI Once/Month subsystem cross-tic valve is closed ~

removed from power valve operator.

Low prcssure coolant injection Except that an (LPCI) may be considered OPERABLE automatic valve during alignment and operation capable of auto-

'for shutdown cooling with reactor matic return to its steam dome pressure less than ECCS position when 105 psig in HOT SHUTDOWN, if an ECCS signal is capable of being manually present may be in realigned and not otherwise a position for another inoperable. mode of operation.

BFN 3.5/4.5-4 hIENOMEe NO; I 77 Unit 3 pAGE~oF~

0 5~i 'ca5o~ 7 6 2.5 AUG 02 8y 3.5.B v S 4.5.B.

Q',ggQ (LPCl and Containmcnt Qg~ (LPCI and Containment Cooling) Cooling) 4.5.B.1 (cont'd) 2~ With the reactor vessel Each LPCI pump shall dclivcr pressure less than 105 psig, 9000 gpa against an indicated the BHBS may be removed system prcssure of 125 psig.

from service (except that tvo Two LPCI pumps in the same BHR pamys-containment cooling looy shall deliver 12000 gym mode and associated heat against an indicated system exchangcrs mast remain yressurc of 250 psig.

OPEBASLE) for a period not to cxcecd 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> vhile 5R

2. kn r tits on the dryvcll being drained of hcadcrs and nozzles suppression chamber quality 34,2e5,Z shall bc conducted once/5 vater and filled vith years. h vatcr test may be primary coolant quality erformed on thc torus headc vatcr provided that during in lieu of the air test cooldown two loops vith one pump per looy or one loop Sce XggC:caliban 4, with two pumps, and ~as

><4 ex+

g, g~H ISTIC associated diesel generators, in the core spray system are OPERhBLE.

3~ If one RHR pump (LPCI mode) 3. Eo additional surveillance is inoyerable, the reactor required.

may remain in operation for a period not to exceed 7 days provided the remanding RHR yamps (LPCI mode) and both access paths of the RHBS (LPCI mode) and the CSS and the diesel generators remain OPERhBLE.

4, If any 2 RHR pumps (LPCI inoperable, the

4. Eo additional surveillance required.

mode) become reactor shall be placed in the COLD SHOTDOWH COHDITIOH within 24'ours. 5Cc ggcHQ~

91=A $ 75 g,g,f PAGE BFH 3.5/4. 5-5 Unit 3 ANENDMENTNO. ~ a o

U9 02 1989 4.5 B

5. If ane RHR pump (containmcnt cooling mode) or associated heat exchanger is inopcrablc, the reactor may remain in operation for a period not to 4cTioe exceed 30 days yrovidcd the R

remaining RHR yumps (containment caoling mode) and associated heat 5qc Wc+Ciech'on+, gyg~g exchanger generators and access go~ Bw> lsd',f.i pa of the RHRS (containment cooling mode) are OPERABLE.

6. If tvo RHR pumps (containmcnt cooling mode) or associated Cegakredv heat cxchangers are I inoperable, the reactor may Ac@ 51 3 6eZ S: /

remain in operation for a period not to'exceed 7 days provided the remains~ RHR pumps (cantainmcnt cooling mode), the assoc ed heat ers iese cnerators and all access of the RHRS (containment cooling made) are OPERABLE.

7~ If too access paths of the RHRS (containmcnt cooling mode) for each phase of the mode ell a rays, ression chamber sprays, and suppression yool cooling) c< tusw~Son Ar Qn~

ars not e t W BF~ XSTS 9,6.Z.D ~g aalu remain in operation for a 3.6.Z. q period not to exceed 7 days provided at least one path far each phase of the mode remains OPERABLE.

scl R& bhl c PAGE OF BHf 3.5/4.5-6 Unit 3 la o

'IENMENTNO.

axnm nt ent If Specifications 3.5.B.l through 3.5.B.7 are not met, an orderly shutdown shall be initiated and the reactor shall be placed in <h +t. %g Sgk%~4 COLD S WN CONDITION Andon i n I2 ~rs nng within hours.

gk

9. When t e reactor vessel 9. When the reactor vessel pressure is atmospheric and. pressure is atmospheric, irradiated fuel is in the the RHR pumps and valves reactor vessel, at least onc that are required to be RHR loop with two pumps or two OPERABLE shall be loops with one pump per loop demonstrated to be shall bc OPERABLE. The OPERABLE per dicscl generators pumps'ssociated Spccif ication 1.0.MM.

must also bc OPERABLE. Low pressure coolant injection (LPCI) may bc considered OPERABLE during alignment and operation for shutdown cooling, if capable of being manually realigned and not otherwise inoperable.

0. If thc conditions of 10. No additional surveillance Specification 3.5.A.5 are met, required.

LPCI and containment cooling are not required.

When there is irradiated fuel ll. The B and D RHR pumps on ia thc reactor and the reactor unit 2 which supply is .not in the COLD SHUTDOWN cross-connect capability CONDITION, 2 RHR pumps and shall bc demonstrated to associated heat exchangcrs, and be OPERABLE per valves 'on an adjacent unit Specification 1.0.MM when must be OPERABLE and capable the cross-connect of supplying cross-connect capability is required.

capability except as specified in Specification 3.5.B.12 below. (Note: Because cross-connect capability is not a gee ~RPcahsn 4r

~" S+< ~5TS r.S.!+V.S>C~cs short-term requirement, a component is not considered inoperable if cross-connect capability can be restored to service within 5 hours.)

AMENDMENT ND. Z 77 BEN 3.5/4.5-7 Unit 3

t ADMINISTRATIVE CHANGES Al 53USTIFICATION FOR CHANGES BFN ISTS 3.6.2.5 - RHR DRYWELL SPRAY Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no .technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

TECHNICAL CHANGES - MORE RESTRICTIVE Ml Surveillance Requirement (SR 3.6.2.5. 1) has been added to ensure that the correct valve lineup for the RHR drywell spray subsystems is maintained. This ensures that the RHR drywell spray subsystems remain capable of providing the overall DBA drywell spray requirement. This change is consistent with NUREG-1433.

M2 CTS 3.5.B.8 requires an orderly shutdown be initiated and the reactor to be in the Cold Shutdown Condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when required RHR drywell spray subsystems are inoperable. Proposed Action 0 will require the plant be in MODE 3 (Hot Shutdown Condition) in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 (Cold Shutdown Condition) in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The addition of this intermediate step to the Cold Shutdown Condition is considered more restrictive since CTS does not require any action to have taken place L

within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completioo 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 safety systems.

BFN-UNITS 1, 2, & 3 Revision 0 PAGE~OF~

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.2.5 - RHR DRYWELL SPRAY TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" LAl Details of the methods of performing surveillance test requirements have been relocated to the Bases and procedures. Changes to the Bases will be controlled by the provisions of the proposed Bases Control Process in proposed BFN ISTS Section 5.0 and changes to the procedures will be controlled by the licensee controlled programs.

"Specific" Ll Proposed ACTION C will allow 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to restore required RHR drywell cooling subsystems to operable status prior to initiating a shutdown.

The proposed 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time provides some time to restore the required subsystems to Operable status, yet is short enough that operating an additional 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is not risk significant. Only 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is allowed since their loss substantially reduces the ability to maintain primary containment within design limits. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> restoration time is considered acceptable due to the low probability of a DBA and because alternative methods to remove decay heat from the primary containment are still available. In addition, if the required subsystem(s) are restored to Operable status prior to the expiration of the 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, a unit shutdown is averted. Thus, the potential of a unit scram occurring while shutting the unit down, which then could result in a need for a subsystem when it is inoperable, has been decreased.

L2 The time to reach NODE 4, Cold Shutdown has been extended from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This provides the necessary time to shut down and cool down the plant in a controlled and orderly manner that is within the capabilities of the unit, assuming the minimum required equipment is OPERABLE. Thisextra time reduces the potential for a unit upset that could challenge safety systems. In addition, a new (more restrictive) requirement to be in NODE 3 (Hot Shutdown) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been added. These times are consistent with the BWR Standard Technical Specifications, NUREG 1433.

BFN-UNITS 1, 2, & 3 Revision 0 PAGE~OF 3,

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

a. Di erent'al pressure betveen a. The pressure ct ferential the dwell ancL suppression betveen the Crjvell ant LCO ~be shall be naincainecf 3 gg g at equal to or greater psiC except as spec'ecf

~ R2.

sayyression c'"amber sha' be "

each akmh~

cl c I 2 hots <~

'ast once (1) and (2) belov:

( ) Ms CI e"mc'al establish'ithin shal'e 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a eviag oyerat~ tcRQeratur iCCj4> Irj r cesar e The cU.fferencial pressure nay be raducecL to 1 ss than 1.1 s 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> r.or to a scheclalei bntdovn.

(2) This Cifferential nay be ctecrease4 co less than 1.1 ysicL for a Qo aaxfmaa of four hours Now Carhg requireL oyerability teston of the HPCI systea, RCIC systea auf the 4ryvell-yressare sayyression chaaber vacuaI breakers.

b If the differential pressure of Specification 3.7.4.6.a and the QgT fog5 cannot be maintainecL cannoc

@if ermcial pressure .It'ho~~

+~ be restorers vithin the subsecLaenc ~ho4, Re4~c< 7lfMnlAL /buaR fn lghrs BPH 3.7/4.7 12 Unit 1

(

PACE l

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP

S aiS a

Dr i Sg Q.io.2.4

a. Differential pressure betveen . a. e pressure dS ferential LCO the dryvell and suppression betveen the dryvell and chamber shall be maintained suppression chambe shall at equal to or greater than 1.1 psid except as spec'fied in (1) and (2) belov:

ach ~.

be recorded at least anc Ia 4<<~

(1) This differential shall be established vithin hours f a eving

~PP '4" '~P 24perat ng tern erature The differential pressure may be reduced to less than 1.1 sid 24 ours r or to a schedu utdovn (2) This differential may be decreased to less LCO than 1.1 psid for a bloke'aximum of four hours during reqrrired operability testing of the HPCI system, RCIC system and the dryvell-pressure suppression chamber vacuum breakers.

b. If the differential pressure of Specification 3.7.A.6.a QCYIohK cannot be maintained arid the 6+8 differential pressure cannot be restored vithin the subsequent eriod Fcd~ rNcM re4L po~gg (5% ii l2 I<rS BFH 3.7/4.7-12 Unit 2

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

Al ambe

a. Differential pressure betveen a. The pressure differential the dryvell and suppression betveen the dryvell and chamber shall be maintained suppression chamber shall at equal to or greater than be recorded at ast once 1.1 psid except as specified in (1) and (2) belov: 82 eac sh~

ls hoclr$

(1) This differential shall be established vithin 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of a ev

~fIi%b;l,'W) erat ng temperature and pressure The erent a pressure LI may be reduced to less than 1.1 si 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> r or to a scheduled utdovn.

(2) is differential may be decreased to less than 1.1 psid for a Leo maximum of four hours Ao&I during required operability testing of the HPCI system, RCIC system and the dryvell-pressure suppression hamber vacuum breakers.

b. If the differential pressure of Specification 3.7.A.6.a ACrloq cannot be maintained and the differential pressure cannot be restored vithin th subsequent ska-hour pQri& h~(.=

Rc~lllcc ~1m~ poult'R Q ~ (y+J~

Ih JQ.h~i s, BFH 3.7/4.7-12 P<QE o Unit 3

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.2.6 DRYWELL-TO-SUPPRESSION CHAMBER DIFFERENTIAL PRESSURE ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

A2 The Frequency for verifying the pressure differential between the drywell and the suppression chamber has been changed to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from shiftly. CTS Table 1. 1 defines shiftly as at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

As such, this is a change in presentation only and is therefore administrative.

TECHNICAL CHANGES - LESS RESTRICTIVE Ll The proposed change revises the required initiation point for establishing differential pressure between the drywell and suppression chamber. By increasing the initiation point following startup to 15%

rated thermal power (RTP) (CTS initiation point is operating temperature and pressure, which is about 1% RTP), the drywell pressure and temperature will have sufficient time to stabilize prior to establishing the required differential pressure. As long as reactor power is below 155 RTP, the probability of an event that generates excessive loads on primary containment occurring within the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of a startup or within the last 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before shutdown is low. 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is considered a reasonable amount of time to allow plant personnel to establish the required differential pressure.

L2 CTS 3.7.A.6.b allows 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to restore the differential pressure before initiating an orderly shutdown, which requires the plant to be in Cold Shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The proposed actions allow 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to restore differential pressure and 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to reduce thermal power to < 151 RTP.

Below this power level, per the proposed Specification, the LCO is no longer applicable (See Comment Ll above).

PAG ~~OF~

BFN-UNITS I, 2, 5 3 Revision 0

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

APA 2 9 1993 (g'i 3.7.F.

est CR 3.7.F.3 (Continued) these primary containment isolation Sc' 3 L5Hfs cR hoA Qr Changers valves is governed by Technical Specification Ae cT5 p q p/q p~

3.7.D.

b. Prcssure control of thc containment is normally performed by VEHTIHQ through 2-inch primary containment isolation valves vhich route effluent to the Standby Gas Treatment System.

The OPERABILITY of these primary containment isolation valves is governed by Technical Specification 3.7.D.

Qi

1. The Containmcnt Atmosphere Dilution (CAD) System shall bc OPERABLE with!

a. Two independent a. clc ach s len id systems capable of 0 crate air t gcn supplying nitrogen v ve ough t to the dryvell and le t on comp te torus e cyc of ull t vcl in a cord cc vit ec fication 1.0.MK and at least once per 5R 3,v,z.t. 2 month verify that each manual valve in the flow path is open.

SR zc.~,t. (

b. A miniam supply of b. Verify that the CAD 2,500 gallons of System contains a liquid nitrogen pcr minimum supply of systems 2,500 gallons of liquid nitrog vic-er week.

BHf 3.7/4.7-22 mMmrN. Zsg Unit 1 PAGE ~ OF~

2 ccig+for) g, Q, p J DEC 07 1994

~z.c.Z.I 2. The Containment Atmosphere 2. When FCV 84-8B is inoper-Dilution (CAD) System shall able, each solen id

+ be OPERABLE whenever the operat d air/nitr en Applt cab; la4) reactor is in the RUN valve o System B all MODE or g~ ~+a /M 2. be cycle through at least one piete cycle f full trave and each m ual valve in the flow path of System B shall be verif open at least once per week.

3. If one system is inoperable,

~

the reactor may remain in ~<M r<d /f2.

ifc7 /o 4 Bean A,(

operation for a period of 30 days provided all active components in the other system are OPERABLE.

4. If Specifications 3.7.G.1 MT(od and 3.7.G.2, or 3.7.G.3 cannot be met, an orderly 8 shutdown shall be initiated and the reactor shall be in Pln pE 3 l4/Olin /2 I} cars

5. Pr ry co tainme pre ure shal be 1 ted to LA 2 axim of 30 sig d ing r ress izati folio ng a los of c olant cident.

6. System may e cons ered OPERABLE with FCV 84-8B inoperable prov ded that all active component in Syst B and all o er

'ctive mponents in System A e OPERABLE.

7. ecification 3.7.G.6 and

4. .G.2 are in feet until the rst Cold Sh tdown of unit 1 fter July 20, 1984 or until January 17, 1985 whichever occurs first.

BFN 3.7/4.7-23 Unit 1

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP

5 ecjgiea4ion 9 6.3: I APR 2 9 t991 3.7.F. a Co a 4.7.F. ot et ue

~St g ~Sst g 3.7.F.3 '(Continued) these primary containment isolation valves is governed by Technical Specification 3.7.D.

Sec ~~s4;4';(~4; 4r e4 )e 4r c.YS S.v.F/47,F

b. Pressure control of the containment is normally performed by VENTING through 2-inch primary containment isolation valves vhich route effluent to the Standby Gas Treatment System.

The OPERABILITY of these primary containment isolation valves is governed by Technical Specification 3.7.D.

0 os e e P,) 4~ ~ ~

CAD Qt,'0 3.6,3.l 1. The Containment Atmosphere Dilution (CAD) System shall be OPERABLE vith:

a. Tvo independent a. Cycle e ch solenoid systems capable of crated air/n rogen supplying nitrogen va ve thr gh a to the dryvell and lea one c piet torus. cycle f full ravel in acco dance vith S ecif n 1.0.MM A/3.4.~.< + and at least once per month verify that each manual valve in the

,S.l.( flov path is open.

p,&

~~ b. gg,g, l I A minimum supply of b. Verify that the CAD 2,500 gallons of System contains a liquid nitrogen per mini&urn supply of system. 2,500 gallons of liquid nitro e vice per vee BFN 3.7/4.7-22 AMENDMENT go. y9 7 Unit 2 pAGE GF

5 cci ic44I 3. cn. 3. I 0)g 07 1994 Al LCo 3.4Y. l 2 The Containment Atmosphere Appfchl,4$ $ Dilution (CAD) System shall be OPERABLE whenever the reactor i.s in the RUN MOD er SgAN'Tup HoD6 HZ If one system is inoperable, Q~

the reactor may remain in

• Acko ~ A P Cl7oN operation for a period of A 30 days provided all active components in the other system are OPERABLE.

4 If Specifi.cations 3.7.G.1 and 3. 7.G.2, or 3. 7.G.3 cannot be met, an orderly Ac. i (os shutdown shall be initiated and the reactor shall be in

]claps 3 i~

5. Primary c tainment pressure 11 be 1 ted to a um of 30 ig durin repr surization llowing loss o coolant accident.

BFN 3.7/4.7-23 NmwBtr HO. 229 Unit 2 pAcs 0F

UNIT 3 CURRENT .

TECHNICAL SPECIFICATION MARKUP

SEMI elk'hD 3 4 3 J 4' 9 )9g) 3.7.F. 4.7.F.

3.7.F.3 (Continued) these primary SCr 3<g+Cl aa$ o n Q Qz+~<

containment isolation valves is governed by ~ C T$ 3,7. F'/9 I F

Technical Specification 3.7.D.

b. Pressure control of the containment ls normally performed by VERTIRQ through 2-inch primary containment isolation valves vhich route effluent to the Standby Gas Treatment System.

The OPERhBILITY of these primary containment isolation valves is governed by Technical Specification 3.7.D,

1. The Containment Atmosphere Dilution (CAD) System shall be OPERABLE vith:

a. Two iILdependent ae cle ach lenoid systems capable of crate air trogen, supplying nitrogen v ve ough a to the dryve11 and le t one comple e torus o cycl of f l,tra el in accordance vlth o .MM and at least once per month verify that each manual valve in the flov path is open.

54 3.4P'. l

b. k minimum supply of b. Verify that the CAD 2,S00 gallons of System contains a liquid nitrogen per minhmun supply of systeme 2,500 gallons of ll id nitrogen per ve ici BPK 3.7/4.7-22 'IIBfllfgffNO, g g g unit 3 PAGE~OF~

0 5 o EC 0 7 1994

.Ai

2. The Containment Atmosphere Lco 7,4.3,t Dilution (CAD) System shall be OPERABLE whenever the reactor is in the RUN RZ o~ A'soup wove II2 Ilotc A ~$ 4stwd If one system is inoperable, hcVion A,l the reactor may remain in

]g4o q operation for a period of 30 days provided all active components in the other system are OPERABLE.

4 If Specifications 3.7.G.l and 3.7.G.2, or 3.7.G.3 lkho w cannot be met, an orderly shutdown shall be initiated 8 and the reactor shall be in N

/ID' /Q ~l NI fht g

5. Prima cont 'nment p essuxe hall b limit d to a Lgz imum rep essuri 30 p j dur tion ollowi g

a loss f cool t ac dent.

BFN 3.7/4.7-23 AMENDMENT NO. I8 6 Unit 3 phd E 3

t BFN ISTS ADMINISTRATIVE CHANGES A1 JUSTIFICATION 3.6.3.1 -

FOR CHANGES CONTAINMENT AIR DILUTION SYSTEH Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

A2 A NOTE was added specifying LCO 3.0.4 is not applicable. Since the current Technical Specifications do not have LCO 3.0.4, stating it is not applicable constitutes an administrative change.

~ A3 Unit 1 CTS 3.7.G.6 5 7 and 4.7.G.2 have been deleted. These Specifications were special provisions that expired January 17, 1985, and therefore, no longer apply. As such, the proposed deletion is considered administrative.

TECHNICAL CHANGES - MORE RESTRICTIVE The Surveillance Requirement has been revised to include each manual, power operated, and automatic valve that is not locked, sealed, or otherwise secured in position.

H2 This change adds MODE 2 (STARTUP NODE) to the Applicability to go along with MODE 1 (RUN MODE) which is already required. The CAD System is required to maintain the oxygen concentration in the primary containment below the flammability limit following a LOCA. Adding a new MODE to the Applicability constitutes a more restrictive change. This change is consistent with NUREG-1433.

BFN-UNITS 1, 2, 8L 3 Revision 0

0 JUSTIFICATION FOR CHANGES BFN ISTS 3.6.3.1 - CONTAINMENT AIR DILUTION SYSTEM Proposed ACTION C is more restrictive since it requires the unit to placed in MODE 3 in 12 hours versus CTS 3.7.G.5 which requires that an orderly shutdown be initiated and the reactor to be in the COLD SHUTDOWN CONDITION with'in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. In addition, since the existing Specification (CTS 3.7.G.2) is only applicable during the RUN mode (MODE 1), failure to meet the existing specification would only require the unit be placed in at least STARTUP/HOT STANDBY (MODE 2) in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> since at that time CTS 3.7.G.2 is again met.

TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" LA1 This Surveillance is being relocated to plant procedures (IST program) since these valves are tested as part of the IST program. As such, it is not needed to be specified as a specific Surveillance Requirement.

If during testing or routine use of the system they are found to be inoperable, the appropriate ACTIONS would be taken. This change is consistent with the BWR Standard Technical Specifications, NUREG 1433.

This requirement has been relocated to plant procedures. This type of

~

LA2 action is a post-accident action routinely governed by the emergency operating procedures. Any changes to the procedures would be controlled by the licensee controlled programs.

"Specific" I

Ll The Frequency of this Surveillance has been extended to 31 days, similar to other surveillances on tank content (e.g., diesel fuel oil). The nitrogen tank contents only decrease when nitrogen is being added to the drywell, and this evolution is a manually actuated and secured evolution (i.e., it is a very controlled evolution). If nitrogen was being added, it would be monitored more closely. Thus, since there are very positive means to ensure nitrogen tank volume is monitored if being used, and volume does not decrease due to "automatic, unmonitored" use, the 31 day Frequency is considered appropriate.

BFN-UNITS 1, 2, & 3 Revision 0

CH 3.7.4.4 (Conc, 4.7.L.4 (Cans'd)

c. zo dryveLL-suppression c. "=ach vac~ breaks valve chamber vacuum breakers shall be insyecccd for may be determined to be propex ayeracian of the oyerable fox opening. valve lnd lent sW-ches in accordance vith Spec'f'cat,'oa L.Q.. C.

4. If Spec'f'cac'ans 3.7.4.4.a, d. 4 leak test of the dz:~el See Yuu,+h>> 3.7.4.4.b, or 3.7.4.4.c. ta suyyressian chamber I'~F-8~

cannoc be met, the unit shall be placed ia a structure shall be conduct 4 during each oyerasiag cycLe.

<Ts 3417 COLD SHUTDOWE COND~OH in Acceptable leak rate is aa order'y mana 0.09 lb/sec eC'rimary 24 hours. consainmeat, atmosphere vich si dif~a tacial.

Se 3.C.a.z, t Lfo ~A3. a. Cantainmeac acmosyhere shall be a. The yrimary containmenc reduced to less thaa 4Z oxygen oxygea coaceatration shall v as 4uring reaccox be measured c yovex o erati x'

re+t il ea s oxyg 1 be ad] ced oa LOAN ig>>

except as specified in 3~ eke ~ ~ so acc unt or ~ SI'in of by ad ing redetersdn in

b. Vi~

subsequent Ql'eh'.lip in the the 24-hour yeriod co lacing the reactor

. D folloving a shut dova, the containment atmosphere oxygen concentrasioa shall be

b. The o

~ p tho us to imary cant inmen gea conc erat, an be cali ased nce very efueling cycle

'l asure reduceci ro less than 4 by volume maintained in this condition.

Deiaex'cing may commence ur prior to a shutdova.

C~ .fysuyyl ro the pa a r is cic be rol used C. The contxol air supyly valve or the pneumat c con~o1 L43 s tea'e th reacco shall n pr caa caacai s be sca eac, ed, cern inside ch primary ca ainment, shall e ver.'fied ar ac po r, the actor sh 11 clos priox to rea or star=. p be b ught to a COLD OMÃ 4 monthly the eaft COHDIT ON vf.~a 24 hours.

d. If Specificatioa 3.7.h.5.a d P(op W T]o~ A L2 3.7.A.5.b cannot bc 1

mec su ovasa be Acrtod initiated aad the reaccor shall be in a COLD SHUTDOWN CONDITION 5 vithia 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> BFH 3.7/4.7-11 AMENOMENT >to y> 9 Unit 1 PAGE~OF~ .

NOV 22 t888 S ec,4~6 < ~a~,Z S ."-OR 5P RPiIOH 3.7.A.4 (Coat'd) 4 7.L 4 (Cont'd)

c. Tvo dryve3~-suppression Co Each vacuum breaker, valve chamber vacuum breakers shall be insyectcd'or may be determined to be proper operation of ."c inoy'erable for oy~ valve aacL Limit svit"'"es in accordance vith Specif icatioa 1.0.%$ .

5'8Z ZVs7IPICgg~g d. Zf Syecificatioas 3.7.4.4.a, k leak test of the d~ell FOR CPANCrES FOR .b, or .c cacaos be met, the to suyyressioa chamber BFN O'TS Z.g.l.7 unit shall be ylaced in a structure shall be conducted Cold Shutdovn condition ia duri1sg each operating cycle aa orderly manner vithia acceptable leak rate L's 24 hours. 0.09 lb/sec of primary, containmcat atmosphere vith 1 psi differential.

a. Containment atmosphere shall be S~~>>~' primary'ontainment L Cg 3.$ .53- a. The reduced to less than 4X oxygen oxygen concentration sha

v ro as duriag reactor be measured d c~

over oyeratio pith~eacror dail e oxygen c 1 t sacs 'lboveMOO~s except as specified in 3.7.i..b.

L42 measurem t

of ccount 'he methocL shall b adjusted unc ed by ad tainty g

Ll a predetermined error funct.'o

b. Mithin the 24-hour pcr The thods ed to casus A~(ie<L;l,<g subsequent to y aciag the reactor thc y ry c tainme in the UH mo folloviag a shut- gen acentr ion sh 11 dova, the coatainment atmosyhere be alibr tcd onc every oxygen conccatration shall be refuel reduced to less than 4X by volume aad maintained ia this condition.

einert may commence 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> yrior to a shutdovn.

LS c. Zf plant control air is being used co The control air suyyly valve t supply the tic coa ol f the pneumatic control sys em inside pr cont t, sys cm inside thQ prima the actor shall a t be start coat cat shallibe ver ied or if t to a Cold be brou pover, the eactor shall utdovn close rior to reagtor s rtuy and mon y thereafter.

coaditioa vithin 24 hours.

d. If Specification 3.7.'A.5.b 3.7.JL..a and a~An-(oN A canaot be me 67/54 order y s ut ovn s e initiated and the reactor shall be 8 in a Cold Shutdovn conditioa vithia.24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

BFH 3.7/4.7-11 Ah!B~DMB" ~~~.

Unit 2 yg ~

~<

PAGE J t

NOV 22 Icy;

(

3.7.A.4 (Cont'd) 4.7.A.4

c. Two drywcll-suppression c. Once each operating cycle, chamber vacuum breakers tach vacuum breaker valve (Cont'cc.

may bc determined to bc shall bc inspected for inoperable for opening. proper operation oi the valve and limit switches in accordance with Specification 1.0.MM, Qu5+gc4gA)

Oa~ Pa d. If Specifications 3.7.A.4.a, d. A leak test of thc drywcll QFt0(5g> g.g~,g 3.7.A.4.b, or 3.7.A.4.c, to suppression chamber cannot be met, the structure shall be conducted unit shall bc placed during each operating cycle.

in a Cold Shutdown Acceptable leak rate is condition in an orderly 0.09 lb/scc of primary manner within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. containment atmosphere with 1 si differential.

I Lac 3,e.v.z

a. Containmcnt atmosphere shall be reduced to less than 4X oxygen t o power operation res ure except as spec as e

during reactor t a~o ove 00+sig n 3.7.A. .b.

5g 3 b,X 2.l L7

~Z

a. The primary containment oxygen concentration be measu dail to e urem a coun of th meth d used a pred e oxy en t sha for th o

shall d

be a ust d unce ain y ad rmi d error function WY g

b.. Within the 2 our period c meth s used to me urc subsequent to placing the reactor th prima coats cnt in the UH mod following a shut- oxy n conc ntrati shal

~ down, thc containment atmosphere be ca ibrate once e ry oxygen concentration shall be refuel cycl .

reduced to less than 4X by volume and in this condition.

4 Deinerting may commence 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to C~ plan con ro a s e ng used c. control ai supply valve o supply e pneuma c control fo thc pneumati control s tem insi primary ntainment, syst inside thc imary the reactor s ll not be tartcd, or i at power, he rcacto shall contai ent shall be closed p rifi r to reactor startup be bro t to a C d Shutdo d monthly thercaftcr.

condition within 24 ours.

l2

d. If thc specifications of 3.7.A. .a Plop st gh'Ogg through 3.7.A.5.b cannot bc met khon an or cr y s ut own shall bc B

initiated and the reactor shall be in a Cold Shutdown condition PAGE~OF~

within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. AMENDV:E~lT N~. 18 C' BFH 3. 7/4. 7-11 Unit 3

AlUSTIFICATION FOR CHANGES BFN ISTS 3.6.3.2 PRIMARY CONTAINMENT OXYGEN CONCENTRATION ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

A2 This statement has been deleted since it is unnecessary. With the reactor in power operation, reactor coolant pressure will always be above 100 psig.

TECHNICAL CHANGES - MORE RESTRICTIVE The requirement to place the plant in Cold Shutdown condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when the limit is not restored within the required Completion Time is revised to reflect placing the plant in a non-applicable condition.

CTS 1.0.C. 1 states action requirements are applicable during the operational conditions of each specification. Therefore, the requirement to place the plant in Cold Shutdown is not applicable if thermal power is reduced to < 15% RTP (outside the applicable condition) within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The current action allows 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to place the plant in a non-applicable condition. As such, this is an additional restriction on plant operation.

TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" LAl The details of how to reduce oxygen concentration to less than 4% have been eliminated from the ISTS. This type of detail will be retained in plant procedures and/or system operating instructions.

the methods of performing sorveillances has been relocated to

~ LA2 Details on BFN-UNITS 1, 2, & 3 Revision 0 PAGE~OF

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.3.2 PRIMARY CONTAINNENT OXYGEN CONCENTRATION plant procedures. Changes to plant procedures will be controlled by the licensee controlled programs.

LA3 Requirements for controlling the use of plant control air to supply the pneumatic control system inside the primary containment and the associated surveillance have been relocated to the Technical Requirements Manual (TRN).

LA4 The requirement to record the containment oxygen concentration will be relocated to plant procedures. Changes to plant procedures will be controlled by the licensee controlled programs.

"Specific" Ll The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowance for inerting on startup has been changed to allow 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after exceeding 15% power instead of the current Run Mode requirement (approximately 5%). The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowance for de-inerting on shutdown has been changed to allow 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to reducing below 15% power. These small differences provide some added time to inert or de-inert the drywell, and provide consistency with BWR Standard Technical Specifications, NUREG-1433. These minor changes are justified, since the time allowed without an inerted drywell is. only increased slightly, and the fact that at low power levels, hydrogen generation is very small compared to higher power levels.

L2 Currently, no time is provided to restore oxygen concentration to within limit prior to requiring a plant shutdown. Proposed Required Action A. 1 and associated Completion Time will allow 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to restore oxygen to within the limit prior to requiring a plant shutdown. During this time, the CAD System is normally still OPERABLE, thus a means to prevent combustible mixtures still exists. This new ACTION would possibly prevent unnecessary shutdown and the increased potential for transients associated with the shutdown.

L3 The periodic verification of oxygen concentration in the primary containment has been changed from a daily verification to a weekly verification. The primary containment is inerted to maintain oxygen concentrations within limits. The primary containment leak rate is established for each operating cycle and any changes during normal operation usually occur very slowly. Other changes to primary containment integrity, such as PCIV operability problems, are indicated by other means to the plant operator and appropriate actions are contained in other technical specifications.

BFN-UNITS 1, 2, 5 3 Revision 0 PAUE~OF~

UNIT 1 CURRENT TECHNICAL SPECIFICATION MARKUP

4 4.7.B.

3.7.B.4 (Cont'd)

b. Place all reactars in sc< Duswg'~So n *r changes at least a HOT SHUTDOWÃ A e~~ iSrs Z.s,q.p COHDITIOS vithin thc next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUTDOWÃ COIITIOH vithin the follovi 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Secondary containment W~~g, 1. Secondary containment 4RmSRiP surveillance shall be reactor zone at all times performed as indicated except as specified in belov:

3.7.C 2~ ,gq, 5 3b9('k

a. Secondary conta nmcnt

>~<81 capability to maintain

',1/4 inch of vater vacuum

~l ca vi i 4ns uw '~

h) on P2 vith c ra of not ore tha 12,000 cfm sh dcmonstratc t cych

&~&lTlnN g+~ Ofba bl~ r ue ng ut e Qio r Lhmw

2. If reactor zone secondary 2. Af r a s condary containment i,aeeg+44y<cannot ca tai nt v lation is be maintained the folloving ~2 term ed, he sta dby gas conditions shall be met:

N~k. 4 ecu; t'., I teat nt oper cd i ediat s stem v ll ly ter a

bc

a. Suspend all fuel handling the ffec ed zon s ar Lz. operations, core altera- iso ated from t e re ainde tions, and activities vith of the econda A-CT(on/ the potential to drain any c tai cnt t con irm i C reactor vessel containing abili to m inta n th fue . rema ndcr o the scco ary t~aebwk( can inmen at 1 4-i h

b. Restore reactor zone of vater egati e pr ssurc secondary containmcnt under calm vind con itions AC7(g~5 integrity vithin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or place all rcsctars in at least a HOT SHUTDOWN COHDITI05 vithin the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUT-DOWN COHDITI01 vithin the folloving 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

BFS Unit 1 3.7/4.7-16 AMENDMENT NO. I 74

Cl 3 Secoada containment integ-rity s 11 be main ined in the r ueliag xone except as spec ied in 3.7. .4.

4. IS refueliag x c secon ry taiament c ot be t

atained conditions llfollowi be t:

g

a. Handl g of s t fuel and all rations over spent fue pools an open re ctor wcl s contai ing fuel shall be prohibit d.

b. The stan y gas tr atmeat system ction to he refuel g xone w 1 be block d except ra cont oiled lea c are six to ass the ach evtag of vacuum of at least 1/ inch of water and aot ov r 3 inch s of water ia 1 three reactor xones.

cable ii is is reactor one y appli- &e xush'f

~ SF'SrS,

~~~ A ~

C~ Q 3.4,t.p integrity is required.

D. D

1. Rhea Primary Containmeat. l. The primary containment Integrity is required, all isolation valves primary containmeat isolation surveillance shall bc valves and all reactor performed as follows:

, coolant system instrument line flow check valves shall a. ht least once pcr oper-bc OPERhBLEc except as ating cycle, the OPER-

~ pecified ia 3.7.D.2. .hBLE primary contain-ment isolation valves

+Locked or sealed closed valves that are power operated may be opened on an inter- and automatically mittent basis under initiated shall be istrative control tested for simulated automatic initiati bFN Unit 1 3.7/4.7-17 AMENMER NL I8 9 PAGE OF

I

~

UNIT 2 CURRENT.

TECHNICAL SPECIFICATION MARKUP

Cl 0

S i4co4iam 3.l .Q. t MAR 30 1%0 3.7.B. S t 4.7.B. ta db Gas ea

$2U: tt9)

,3.7.8.4 (Cont'd)

b. Place all reactors in Qc,Suf,4i(i cak> e~ for C~~~pg at least a HOT SHUTDOMH Qr9t td iSTS R,C, k3 COHDITIOH vithin the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHDTDOWH COHDITIOH vi thin the folloving 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3.7.C. S o d Ca a e t 4.7.C. Seep da Co ta nt

1. Secondary containmen 1. Secondary containment shall be in the surveillance shall be reactor zone at all times pcrfarmed as indicated except as specified in bclov:

3.7.C.2. > >q,(,3+sR3 oPenRB~ econdary containment capability to maintain

/p( 1/4 inch of water vacuum HR

(<

v th er m

c~v h bandit a system on leakag

()L 'i~

i%a ~

~

rate of not more tha Ll 12,000 cfm shall be demonstrated houP-govwn<oeJ A+~ uagngou~ge >

ze 0 )

LAO to rc cli

2. If reactor conc secandary 2~ Aft a se ondary containment 4ae~~ cannot co tainme t viola on is be maintained the folloving termi d, the tandby gas Lo- c ns shall bc met: treat nt sys m vill b Re i~ Ae4ia oper ted i diately fter,

a. Suspend all fuel handling th affec d zones re t'ions, QL<(ot4 apcratians, core altcra<<

and activities vith the potential to drain any i olated from th remainder f thc conta econda cnt t confirm ts reactor vessel containing abil ty to intain e i~ka4Q remainder f the se anda containm t at 1/ inch

b. Restore reactor zone of wate negativ pre ure A~<" secondary cantainment under calm vind conditions.

A<@ integrity vithin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or place all reactors in at least a HOT SHUTDOWH 4 SPY 3.4- l l COHDITION within the next a,~dL z.c, V. (.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUT-DOW COHDITIOH vithin the folloving 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

BFH 3.7/4.7-16 AMENOMENT gp. y77 Unit 2 PAGE~OF~

~p<<Aicc~io~ 3.6. 4 (

SSES

3. Secondary c ntainment integ-rity shall e maintained in the rcfu ing zone, except as, specifi d in 3.7.C.4.

4. If r ueling zone secondary con ainment cannot be m ntained the folloving nditions shall be met.

a. Handling of spen fuel and all operations ver spent fuel pools open reactor veils conta ing fuel shall bc prohib ed.

b. The st dby gas treatm nt syst suction to the ref cling zone vill e b eked except for a ontrolled leaks area sized to assure the achieving, of vacuum of at least 1/4 inch of vater and not ov 3 inches of vater in zones.

ll three reactor is is only appli-cable if reactor zone Sec,

• ~

guS g Cr+A'on Crt A>> gCgg integrity is required. Ben/ isrS Z.C.l.g a Co ta a o D. ma Co ta e t Isolat o V~a~

1. Shen Primary Containmcnt 1. The primary containment Integrity is required, all isolation valves primary containment isolation surveillance shall be valves and all reactor performed as follovs:

coolant system instrument line flov check valves shall a. At least once per oper-be OPERABLE* except as ating cycle, the OPER-specified in 3.7.D.2. ABLE primary contain-ment isolation valves

• Locked or sealed closed valves that are povcr operated may be opened on an intermittent and automatically basis under administrative control. initiated shall be tested for simulated automatic initiation BiH 3.7/4.7-17 NENOMEHT NO. 2 04 Unit 2

CURRENT TECHNICAL SPECIFICATION MARKUP

,

3.7.B. S s .B. a eat ent kama 3.7.B.4 (Cont'd)

b. Place all reactors in S<~ wustj$ i ~*'o r) at least a HOT SHUTDOWH CholcS Fo r GV~ ISTs COHDITIOH within the next 3oL Qe3 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUTDOWH COHDITIOH vi thin hc folloving 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3.7.C. Seco da Co ta e 4.7.C. Seep da Containment

1. Secondary containment shall be ma nta nc n the surveillance shall be reactor zone at all imes performed as indicated

>Pal'caYiliFy 'xcept as spccificd in below:

3.7.C.2. SR 3.4.4I.3 8-sR . o.l.

PcRAbl a. Secondary containment CO not app ca e capability to maintain prior to load ng fuel into 1/4 inch of vater vacuum c Unit 3 rca tor vcs 1, er aim vn lOi~n pr vided the Uni 3 rcac r mp c di on zone s not requir for vith system nlea ag second containment rate of not more tha integrity for other 12,000 cfm shal emonstrate at eac e e ng o tage rior CoaD'Ihonl g+c fcrobl8 o fu i

2. If reactor zone secon ary After scco dary cont nmen viol tion is containment iaeegekty cannot bc maintained the folloving det rminc , the stand gas ons shall bc mct: tr atm sys vil be r+pesek Note 4o n C.) o cra d imm iatel after

a. Suspend all fuel handling the fecte zones are operations, core altera- iso atcd f om the remainder tionsp and activities with of hc sc ondary thc potential to drain any contai nt to onfi its reactor vcsscl containing abilit to ma tain fuels der of he se onda e'emai tA&ilFel cont inmcn at 1/ inch

b. Restore reactor zone f vater egativ pres re secondary containment dcr ca vind onditions RC&n> integrity vithin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or place all reactors in R.+B at least COHDITIOH a HOT vithin SHUTDOWH the next

~

/tdd Sls Xg,q, 3i6,$ , t,+

~, ~

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUT-DOWH COHDITIOH vithin the folloving 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

BFH 3.7/4.7-16 NENOMENT NO. 159 Unit 3 WGE~OF~

sPec,,g z.s.M. t econdary con ament integ-rity ahal e maintained in the re ling xone, exec as spec led in 3.7.C.4.

5 refueling xon secondary containment c ot bc maintained e folloviag conditio shall bc met:

ae ling of sp fuel and all operatio over spent fuel pools open reactor veils co aining fuel hall bc pro bited.

b. Th standby g treatment stem suet n to thc refucll one vill be blocke except for a contr led leakage are six d to assure the a eving, of a va of t least 1/4-in of vatcr and not over inches of vater in a three reactor xoncs. s is only appli- $c'w Fu~f4 cdjog Qr Cjg~

cable i reactor zone W 8% lsT5 3.t .I.3 intcgr ty is required.

D D. spa o

1. When Primary Containment 1. Thc primary coataiameat Integrity is required, all isolatioa valves primary containment surveillance shall be isolation valves and all performed as follovs:

reactor coolant system instrment line flov check a. At least once per oper-valves shall be OPERABLE* ating cycle, the OPER-except as specified in ABLE primary contain-3.7.D.2. ment isolation valves that are povcr operated

<<Locked or sealed closed valves and automatically may bc opened on aa latczmittent initiated shall be basis under admiaistratlve control. tested for simulated automatic initiation BPK 3.7/4.7-17 Unit 3 AMENDMENT,Ng g6 I

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.4.1 - SECONDARY CONTAINMENT ADMINISTRATIVE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

A2 The definition of SECONDARY CONTAINMENT INTEGRITY has been deleted from the proposed Technical Specifications. In its place the requirement for secondary containment is that it "shall be OPERABLE." This was done because of the confusion associated with these definitions compared to its use in the respective LCO. The change is editorial in that all the requirements are specifically addressed in the proposed LCO for the secondary containment and in the Secondary Containment Isolation Valves and Standby Gas Treatment System Specifications. The Applicability has been reworded to be consistent with the new definitions of NODES and to have a positive statement as to when it is applicable, not when not applicable. Therefore the change is purely a presentation it is preference adopted by the BWR Standard Technical Specifications, NUREG-1433.

A3 Amendment 159 to Unit 3 Technical Specifications added a provision to allow separating the Unit 3 reactor zone from the secondary containment envelope under certain conditions (prior to fuel loading) to expedite Unit 3 constructions activities'during Unit 2 operation. This provision is no longer needed and can no longer be applied. Therefore the

• Note to TS 3.7.C.1 has been deleted. This change is considered administrative since it deletes a requirement that no longer applies.

TECHNICAL CHANGES - MORE RESTRICTIVE Ml This Surveillance in two parts)

(it appears has been broken to be only one Surveillance, though into two separate Surveillances, SR it is BFN-UNITS 1, 2, 5 3 Revision 0 PAGE~OF~

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.4.1 - SECONDARY CONTAINMENT 3.6. 1.4.3 and SR 3.6.1.4.4. The tests will ensure the ability of the secondary containment to maintain I/4 inch vacuum, and in addition, SR 3.6.4.1.3 will ensure the vacuum is attained in 120 seconds, while SR 3.6.4.1.4 will ensure it maintains the vacuum for I hour. These new requirements are additional restrictions on plant operation.

H2 The analysis for secondary containment drawdown assumes two SGT subsystems are needed. Thus, the test now specifies the minimum number of'operating SGT subsystems and the total flow rate. To ensure all three SGT subsystems are tested (since the test does not specify that all SGT subsystems must be tested) the Frequency is on a STAGGERED TEST BASIS, which will ensure all three SGT subsystems are tested in 2 cycles. These are additional restrictions of plant operation.

Two new Surveillance Requirements have been added. SR 3.6.4.1. 1 will verify that all secondary containment hatches are closed and sealed every 31 days. SR 3.6.4.1.2 will verify that each access door is closed, except when used for opening, and then one door is closed, every 31 days. These are additional restrictions on plant operation.

M4 This change requires the movement of irradiated fuel in secondary containment and CORE ALTERATIONS to be "Immediately" suspended secondary containment is inoperable. In addition,,action must be if "Immediately" initiated to suspend operations with the potential to drain the reactor vessel in this Condition. The current specification does not establish a time limit to suspend these activities.

Immediately suspending these activities minimizes the probability of a fission product release if a reactivity event occurs while the secondary containment is inoperable. Also, immediately initiating action to suspend operation with the potential to drain the reactor vessel will minimize the potential for reactor vessel draindown and subsequent potential for fission release. Imposing a time limit to suspended these activities is a more restrictive change.

The reactor building is divided into four ventilation zones which may be isolated independently of each other. The refueling room which is common to all three units forms the refueling zone. The individual units below the refueling floor form the other three reactor zones. The zone system is not an engineered safeguard, and the failure of the zone system would not in any way prevent isolation or reduce the capacity of the Secondary Containment System. If the internal zone boundaries should fail, the entire reactor building still meets the requirements of secondary containment. CTS 3.7.C requires, the secondary containment integrity to be maintained in the reactor zone and refueling zone at all times except as specified in 3.7.C.2 and 3.7.C.4 respectively. If secondary containment cannot be maintained in the reactor zone, fuel BFN-UNITS I, 2, 5 3 Revision 0 PAGE

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.4.1 - SECONDARY CONTAINMENT secondary containment must be restored within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or all reactor shall be shut down. If secondary containment cannot be maintained in the refueling zone, the handling of spent fuel and all operations over spent fuel pools and open reactor wells shall be prohibited.

Currently, a combined secondary containment integrity test is performed to demonstrate Technical Specification operability. In addition, due to leakage between zones, zone integrity is difficult to maintain. As such, secondary containment integrity is maintained on the three reactor zones and the refueling zone at all time. Therefore, the separate Specification that only prohibits the handling of spent fuel and all operations over spent fuel pools and open reactor wells when refueling zone integrity is not maintained is not necessary and has been deleted TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" LA1 This design detail/requirement has been relocated to the Background section of the Bases for ITS 3.6.4.3, "Standby Gas Treatment System,"

and to plant procedures governing this Surveillance Requirement. Any changes to this requirement will require a licensee controlled program evaluation.

LA2 The requirement to operate the Standby Gas Treatment System after a secondary containment violation is determined and has been isolated (i.e., restored) to check if it can maintain the proper vacuum is being relocated to plant procedures. Any time the OPERABILITY of a system or component has been affected by maintenance, replacement, or repair, post maintenance testing is required to demonstrate OPERABILITY of the system or components. Explicit post maintenance surveillance testing has therefore been deleted from the Technical Specifications and will be relocated to the appropriate plant procedures. Any changes to the requirement will require a licensee controlled program evaluation. This change is consistent with NUREG-1433.

"Specific" L1 The proposed surveillances for the 1/4 inch vacuum tests do not include the restriction on plant conditions that requires the surveillances to be performed during a refueling outage, prior to refueling. These Surveillances could be adequately performed in other than a refueling outage without jeopardizing safe plant operations. The control of the plant conditions appropriate to perform the test is an issue for procedures and scheduling, and has been determined by the NRC Staff to BFN-UNITS 1, 2, & 3 Revision 0

JUSTIFICATION fOR CHANGES BFN ISTS 3.6.4.1 - SECONDARY CONTAINMENT plant conditions appropriate to perform the test is an issue for procedures and scheduling, and has been determined by the NRC Staff to be unnecessary as a Technical Specification restriction. As indicated in Generic Letter 91-04, allowing this control is consistent with the vast majority of other Technical Specification surveillances that do not dictate plant conditions for the surveillances. The proposed change to the 18 month frequency also effectively increases the surveillance interval. The current Technical Specification for all three units requires performance at each refueling outage prior to refueling. Since the secondary containment is common to all three BFN units, with all three units operating, this could result in performance of the same test at an average of every 6 months. The change to the 18 month frequency will allow this test to be performed once and applied to all three units Technical Specifications. Since operating experience has shown these component usually pass the Surveillance at the 18 month frequency, the frequency is considered acceptable from a reliability standpoint.

L2 Required Action C. 1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operation and the inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown. By adding an exception to LCO 3.0.3 for the failing to suspend irradiated fuel movement, an LCO 3.0.3 required reactor shutdown is avoided in MODE 1, 2, or 3. However, the plant would still be required to shutdown after 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> per proposed Required Actions B.l and B.2 in addition to suspending fuel movement per Required Action C.l.

BFN-UNITS 1, 2, 5, 3 Revision 0 PAGp~OF~

UNIT 1 CURRENT TECHNICAL SPECIFICATION It MARKUP PAGF~OF~

~3 6. Y-2.

MA 80 1980 SURVBILLASCE REQUIRENESTS 3.7.B. 4.7.B.

3.7.B.4 (Cont'd)

SC' 34s~A cw6 hr C~cs

b. Place all reactors in

<

@~ BFrd t 5 TS Z, C. /.Z at least a HOT SHUTDOMH COIITIOK vithln the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUTDOMf COlIDITI01 vithin the folloving 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

4.7.C.

Secondary contalnmcnt integrity 1. Secondary containment shall be maintained in the surveillance shall bc f~ seat L4p 3,&Ac%

reactor zone at all times performed as indicated

+ except as specified in bclov!

~i:cab'3i 3.7.C 2

a. Secondary containment

+3 k +H) Oq5 capability to maintain hfo~

'jiopogCg(

P 1/4 inch of vater vacuum AF under calm vlnd f~.~~~ nkk l h +6o~s (< 5 mph) vlth conditions a system leakage rate of not more than 12,000 cfm, shall be demonstrated at each refueling outage prior to refueling.

2~ If reactor zone secondary, 2. hftcr a secondary containment integrity cannot containment violation is be maintained the folloving determined, the standby gas 4 kz~~X conditions shall be mct: trcatmcnt system vill bc operated immediately after

~g p. a. Suspend all fuel handling the affected zones are operations, core altera- isolated from the remainder ACT(oQ tions, and activities vith of the secondary b the potential to drain any containment to confirm its reactor vessel containing ability to maintain the fue . remainder of the secondary I th~ +kl containment at 1/4-inch

b. Restore reactor zone of vatcr negative pres'sure ACT(o~> secondary containment under calm vind conditions.

h>t integrity vithin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or place all reactors in Sc'c >uSK Pi ecHo~

t least a HOT SHUTDOWN 4~ I~A t575 r,~.q,i COlIDITIOH vithin the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUT-DOMÃ CO%)ITIOUS vithin the k pseud SRs ~.6.q,a,i >3.0 7 >.z.

olloving 24 hours.

BFS 3.7/4.7-16 AMENOMEHT No. X 74 Unit 1

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP PAGE ) OF

LI p) 3 '.B. S s c 4.?.B. a Ga J.7.B.4 (Cant'd)

b. Place all reactors in ~~~> 4 C&k>6M gyp at least COHDITIOH a HOT SHUTDOMH vithin

'12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD the next

~

~CC.

RFIV I ~S'.QQ3 Qg g~g~

SHDTDOMH COHDITIOH within the folloving 24 hours.

4.7.C. Seep da Conta e

1. Secondary containment integrity 1. Secondary cantainment roPoM shall be maintained in the surveillance shall be L,co 3.(i.4.2. reactor zone at all times performed as indicated ppplic%Lal~Q except as specified in belov:

3.7.C.2.

a. Secondary containment capability to maintain 1/4 inch of vater vacuum Pr3 under calm vi.nd (c 5 mph) conditions g g ~ g fg 4o AGTl6 vith a system leakage rate of not morc than 12,000 cfm, shall be

'PropS<cg Afoot 1 demonstrated at each ko Aaml o eS refueling outage prior ta refueling.

If reactor zanc secondary 2. After a secondary containment integrity cannot containment violation is be maintained the folloving determined, the standby gas VrspoSaD Ar~'rW hb4' conditions shall be met: treatment system vill be Qadi~ b I operated immediately after

a. Suspend all fuel handling the affected zones are Ag<latJ operations, core altera- isolated from the remainder tions, and activities vith of thc secondary the potential to drain any containment to confirm its reactor vessel containing ability to maintain the s M~eLag tf remainder of the secandary containment at 1/4-inch

b. Restore reactor zone of vater negative pressure LI secondary containment under calm wind conditions.

p,et(~~ integrity vithin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, A<8 or place all reactors in t least a HOT SHUTDOMH See V~stll(ca4e~ 4r 'CL4~pg COHDITIOH vithin the next 4r 2 Fhl I s'75 g. (, t/.

12 hours and in a COLD SHUT- /

DOMf COHDITIOH within the folloving 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. +-p.s d Ses 3.<AZ.I, Z.C,g.Z.Z.

BFH 3.7/4.7-16 MEHDMENT NO. yqy Unit 2 pp,Q~

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP PAGE OF

NOY $ 8 1931 3.7.B. at st .7.B. ta d Gas eatment

~S~t 3.7.B.4 (Cont'd)

b. Place all reactors in at least a HOT SHUTDOWH See rus<4cc t)'o~ fa COHDITIOH vithin the next ch nysA,~ 8su isrs 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD 3.4 S. 3

~

SHUTDOWH COHDITIOH vithin the folloving 24 hou 4.7.C. Seep da Containment

1. Secondary containment integrity Secondary containment shall bc maintained in thc surveillance shall be t'i~gk reactor zone at all times performed as indicated LCP 3.fegeL 4

~l, Calpi (el) except as specified in belov:

3.7.C.2.

a. Secondary containment

+ LCO not applicable until jus capability to maintain rior to loadi fuel i o 1/4 inch of vater vacuum Unit 3 reac r vessel, under calm vind pr o ded the Unit reacto (< 5 mph) conditions zone not require for vith a system inleakage scconda containment rate of not more than nte ri units. 12,000 cfm, shall be demonstrated at each Pro~ +kg gM3*QW refueling outage prior p> g pM I ~AAo~s to refueling.

2~ If reactor zone secondary 2~ After a secondary containment violation is containment integrity cannot be maintained thc folloving determined, the standby gas conditions shall bc mct: treatment system vill be

>" operated immediately after P.p a. Suspend all fuel handling thc affected zones are operations, core altera- isolated from the remainder tions, and activities vith of thc secondary QhaH the potential to drain any containment to confirm its Z7 reactor vessel containing ability to maintain the remainder of the secondary

~

iyl4q pg g containment at 1/4-inch Ll b. cstore reactor zone of vater negative pressure secondary containment under calm vind conditions.

integrity vithin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or place all reactors in c ~64's'cR$ pa ~ ~ ~~

at least COHDITIOH a HOT vithin SHUTDOWH thc next ~'H 6'rs g.<,q, ~

c$

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUT-DOWH COHDITIOH vithin thc folloving 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. MM 58~ 3.e.s.v.i,3.~.~.i.2.

BFH 3.7/4.7-16 NENOMENT NO. 159 Unit 3 PAGi= > OF

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.4.2 SECONDARY CONTAINMENT ISOLATION VALVES ADNINI STRATI VE CHANGES Al Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

A2 The current definition of Secondary Containment Integrity requires all secondary containment isolation valves (SCIVs) to be OPERABLE or in their isolation position. Thus, the current secondary containment Specification encompasses the SCIV requirements. It is proposed to provide a separate Specification for SCIVs for clarity. Thus, the new LCO will require all SCIVs to be OPERABLE, consistent with the current requirements. The applicability has been reworded to be consistent with the new definitions of MODES and to have a positive statement as to when it is applicable, not when it is not applicable.

A3 Proposed ACTIONS Note 2 (" Separate Condition entry is allowed for each penetration flow path") provides explicit instructions for proper application of the ACTIONS fo'r Technical Specification compliance. In conjunction with the proposed Specification 1.3 - "Completion Times,"

this Note provides direction consistent with the intent of the existing Actions for inoperable isolation valves. Similarly, proposed ACTIONS Note 3 facilitates the use and understanding of the intent to consider the operability of any system affected by inoperable isolation valves and to apply applicable Actions. With the proposed LCO 3.0.6, this intent would not necessarily apply. This clarification is consistent with the intent and interpretation of the existing Technical Specifications, and is therefore considered an administrative presentation preference.

BFN-UNITS I, 2, & 3 Revision 0

0 JUSTIFICATION FOR CHANGES BFN ISTS 3.6.4.2 SECONDARY CONTAINNENT ISOLATION VALVES A4 Amendment 159 to Unit 3 Technical Specifications added a provision to allow separating the Unit 3 reactor zone from the secondary containment envelope under certain conditions (prior to fuel loading) to expedite Unit 3 construction activities during Unit 2 operation. This provision is no longer needed and can no longer be applied. Therefore the

• Note to TS 3.7.C. 1 has been deleted. This change is considered administrative since it deletes a requirement that no longer applies.

I 3

TECHNICAL CHANGES - NORE RESTRICTIVE Two new Surveillance Requirements have been added to ensure SCIV operability. SR 3.6.4.2. 1 verifies that SCIVs isolate within the assumed times in accordance with the inservice testing program. SR 3.6.4.2.2 verifies that each SCIV actuates to its isolation position on an accident signal every 18 months. These are additional restrictions on plant operation.

This change requires the movement of irradiated fuel in secondary containment and CORE ALTERATIONS to be "immediately" suspended secondary containment is inoperable.

if In addition, action must be "immediately" initiated to suspend operations with the potential to drain the reactor vessel in this Condition. The current specification does not establish a time limit to suspend these activities.

Immediately suspending these activities minimizes the probability of a fission product release if a reactivity event occurs while the secondary containment is inoperable. Also, immediately initiating action to suspend operation with the potential to drain the reactor vessel will minimize the potential for reactor vessel draindown and subsequent potential for fission release. Imposing a time limit to suspended these activities is a more restrictive change.

TECHNICAL CHANGES - LESS RESTRICTIVE "Specific" L1 This Action has been changed to allow one valve in a penetration to be inoperable for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, instead of the current 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Proposed ACTION A now requires the penetration to be isolated in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. This is justified since an OPERABLE valve in the penetration remains to isolate the penetration if needed, thus the "leak tightness" of the secondary containment is still maintained. The isolated penetration is required to be verified every 31 days while a valve is inoperable, further ensuring the continued "leak tightness" of the secondary containment. Proposed ACTION B will verify that if both SCIVs in a penetration are inoperable, at least one SCIV in a penetration is closed BFN-UNITS 1, 2, 5. 3 Revision 0

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.4.2 SECONDARY" CONTAINMENT ISOLATION VALVES within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. This maintains consistency with the current requirements. An allowance is proposed for intermittently opening closed secondary containment isolation valves under administrative control. The allowance is presented in proposed ACTIONS Note 1, which allows opening of secondary containment penetrations on an intermittent basis for performing Surveillances, repairs, routine evolutions, etc.

L2 Required Action D.l has been modified by a Note stating that LCO 3;0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If 'moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operation and the inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a,reactor shutdown. By adding an exception to LCO 3.0.3 for the failing to suspend irradiated fuel movement, an LCO 3.0.3 required reactor shutdown is avoided in MODE 1, 2, or 3. However, the plant would still be required to shutdown per proposed Required Actions C. 1 and C.2 in addition to suspending fuel movement per Required Action D. l. However, this shutdown is considered less restrictive since Required Action C. 1 allows the plant to be in Hot Shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> versus Hot Standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> as required by CTS 1.0.C. l. Both CTS and the proposed Required Action C.2 require the plant to be in Cold Shutdown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

BFN-UNITS 1, 2, 5 3 Revision 0

UNIT I CURRENT TECHNICAL SPECIFICATION MARKUP PAGE~0>

o

2. a. The results of the in-place 2. a. The tests and sample cold DOP and halogenated analysis of hydrocarbon tests at g 10K Specification 3.7.B.2 design flow on HEPh filters shall be performed at and charcoal adsorber banks least once per operating shall show g99X, DOP removal cycle or once every and g99X halogenated 18 months whichever hydrocarbon removal when occurs first for standby tested in accordance with service or after every hHSI H510-1975. 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of system operation and following significant painting, fire, or chemical release in any ventilation zone communicating with the system.

b. The results of laboratory b. Cold DOP testing shall carbon sample analysis be performed after shall show 290K radioactive each complete or partial methyl iodide removal when replacement of the HEPT tested in accordance with filter bank or after any hSTN D3803 structural maintenance on the system housing.

c. System shall be shown to c. Halogenated hydrocarbon operate within ply design testing shall be flow. performed after each complete or partial replacement of the charcoal adsorber bank or after any structural maintenance on the system housing.

PAGE ~ uF~

BPK 3.7/4.7-14 NENIMENT KO. 2 15 Uait 1

oscet Ac7-Sg Ra KZ.I operated a ot of at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> every Prl Pn Octad o~s'mule*~ month.

'n i'i a h on s i ng v c Test sealing of g ets or h using door . s pe ormc utf emic smo g er to s du ing e ch t st pe orm for co ian ffca ion vi 7.B..a Spc i k5'eci

~sn ~~<

rom aad after the date tha ~ ao Once per oae train of the standby gas automat c t at on of treatmeat system is made or each braach of the stand<<

found to be faopcrablc for by gas treatmeat system any reasoa, REACTOR POWER emo tratc QTfohl OPERATIOS and fuel handling from e unit'%contr ls.

fs permissible only durfag Sk'xto.9.Z.

the succeeding 7 days unless At least once yer such circuit is sooaer made manual oyerability o OPERABLE, provfded that the byyass valve for duriag such 7 days all filter cooling shall be active componcats of the demonstrated.

other tvo standby gas treatment trains shall be c. When oae train of the operable. s by tre tmen

~pose) <>4 A 4e~~A -ey tern be omcs yer ble o Of C. the other o tr sha 1 be d oastr ed f'n~ ~'ir nL tob 0 vf 2

~

lkAon Q,J hours and daily ther eaf ter.

4~ Zf these coadftioas caaaot HClbnls be met:

a. Suspend all fuel duffy ~o aSc+bli<5 c'~e~4 of lit'agiAk.d.

>~ e~sc&sdtM.Q c<rt& nned-

~

C+Z handling oyerations, dcrlg CoREhLT<AtTIbA, O'Ollr a Q f gpg core alterations, aad activities vfth thc potential to drain

~ - any reactor vessel containing, fuel N AjbtEMDMENT NO. g 7g BEB t 3.7/4.7-15 Unit 1 PAGE

~ ~ ~

Jr. Plass a11 reactors in QcTIoA at least a HOT SHUTDOWN s COIITIOS vithin the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD sr'uz5AwHcn f r Q~

, SHUTDOWN CONDITION vithin A SFW WrS Z;e.V.t the folloving 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3.7.C. 4.7.C. S o

1. Secondary containment integrity l. Secondary containmcnt shall be maintained in the surveillance shall bc reactor xone at all times pcrformcd as indicated except as specified in belov:

3.7.C.2

a. Secondary containment capability to maintain 1/4 inch of vatcr vacuum under calm vind

(< 5 mph) conditions vith a system leakage rate of not more than 12,000 cfm, shall be demonstrated at each rcfucling outage prior to refueling.

If reactor xone secondary 2. hftcr a secondary containment integrity cannot containment violation is be maintained the folloving determined, the standby gas conditions shall bc mct: treatment system vill be operated immediately after

a. Suspend all fuel handling the affected xones are operations, core altera- isolated from the remainder tions, and activities vith of the secondary the potential to drain any containment to confirm its r'eactor vessel containing ability to maintain the fuel. remainder of the secondary containment at 1/4-inch

b. Restore reactor xone of vater negative pressure secondary containment under calm vind conditions.

integrity vithin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or place all reactors in at least a HOT SHUTDOWN COHDITI01 vithin thc next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUT-DOWN COHDITION vithin thc folloving 24 hours.

BPK Unit 1 3.7/4.7-16 AMENOMENT NO I7 4

Cl HAR 3 0 }990

l. Escape ae specified in At least once per year, Specification 3.7.B.3 belov, the folloving conditions all three trains of the shall be demonstrated.

standby gas treatment s stem shall be 'OPERABLS t all a. Pressure drop across cs v ondary the combined HEPA containment integrity is filters and charcoal required. adsorber banks is less than 6 inches of vater at a flov of 9000 cfm (g 10K) ~

b. The inlet heaters on each circuit are tested in accordance

&+ 3~+',f-<~'on/ Qi CA~ with hBSI 8510-1975, 4'< ZC'~ lST'5 Secgo and are capable of an output of at 1'east 40 RV

c. Air distribution is uniform vithin 20X across HEPA filters and charcoal adsorbers BPK 3.7/4.7-13 AMENDMENTNO. 1.74

.-, 5' Unit 1 g

0' C Ts Z g. F/q, 7, F FEB 1 3 1995 5

3.7.F. 4.7.F.

~S

1. Thc pr ry containment p ge l. At le st once every 18 system hall be OPERABLE for mont , the prcssure drop PURGI G, except as spec fied acr ss the combined HEPA in .7.F.2. fi ters and chare al a sorber banks s 11 be

. The results of th in-place emonstrated t be less cold DOP and hal genated than 8.5 inch of vater hydrocarbon tes s at design at system de gn flow flovs on HEPA iltcrs and rate (g LOX).

charcoal adso er banks shall show 99K DOP removal a. Thc te s and sample and g 99K h logenatcd hydro- analy s of Specifica-carbon rem val vhen tested tion .7.F.1 shall be in accord cc vith perf rmcd at least once ASSI 551 -1975. per operating cycle or on e every 18 months,

b. Thc re ults of laboratory v ichever occurs first carbo .sample analysis shall r after 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of shov g 85X radioactive system operation and met 1 iodide removal vh folloving significant te cd in accordance vit painting, fire, or AS D3803 ~ chemical release in any ventilation xo e commmicating vit the

c. System flov rate s 1 be systio shown to be vithin LOS of design flov vh tested b. Cold DOP testi shall in accordance vi be performed fter each ASSI 8510-1975. complete or artial replacement of the HEPA

2. If the provisio of 3.7.F.l.a, filter b or after b~ and c cannot be met, the any struc al mainte-system shall b declared nance on e system inoperable. e provisions of housing, TechnicaL Sp cification 1.C.I do not app . PURGIIC may con c. Haiog tcd hydrocarbon tfaue using the Standby Cas test shall be Treatment System. per rmed after each co lete or partial

3. a. The 18-inch primary contain- re lacement of the ment isolation valves asso- rcoal adsorber bank ciatcd vith PURGIEQ may be o after any structural opea during the RUN mode intensncc on the for a 24-hour period after system housing.

entering the RUB mode and/or for a 24-hour period prior SC< TuSfjCac~hy~ @~

g~

to catering the SHUTDOWH +'Bed lS'Ts 8,v, t,g mode. The OPERABILITY of BFS 3.7/4.7-21 AMBIOVBP gg Ej P.

Unit 1 PAGE OF

UNIT 2 CURRENT TECHNICAL SPECIFICATION MARKUP

3~ 4.

2. a. The results of the in-place 2.'a. The tests and sample cold DOP and halogenated analysis of hydrocarbon tests at g 10Z Specification 3.7.B.2 design flov on HEPT filters shall be performed at and charcoal adsorber banks least once per operat shall shov g99Z DOP removal cycle or once every and g99Z halogenated 18 months whichever hydrocarbon removal vhen occurs first for standby tested in accordance vith service or after every AHSI 8510-1975. 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of system operation and folloving significant painting, fire, or chemical release in any ventilation rane communicating vith the systeme

b. The results of laboratory b. Cold DOP testing shall carbon sample analysis be performed after shall shov g90Z radioactive each complete or partial methyl iodide removal vhen replacement of the HEPT tested in accordance vith filter bank or after any ASTM D3803 ~ structural maintenance on the system housing.

c. System shall be shown to c. Halogenated hydrocarbon operate vithin glOZ design testing shall be flov. performed after each complete or partial replacement of the charcoal adsorber bank or after any structural maintenance on the system housing+

PISWOMEk R+g 3 1 5 BZS 3 7/4.7-14 Unit 2

5pCcificako~ g. g. gp MAR 80 1980

~ A ~ ~ ~

H

~R.*. 'I Pi 4po>ci 447/aAJ Q d. Each train sha 1 be operated a total of at least 10 hours every month.

Test sealing of gaskets for hous doors s all 48'. be pcrfo d utilizi emical sm ke genera

....*a.-.:-/.A4 t s during ch test

',4'iI'yne per rmed. for compl cc vith Speci-ficatian 4.7.B.2.a and Specification 3.7.B.2.a.

S ~.C.V.R.

3. Fram and after the date that 3~ a ce per W'~

one train of the standby gas automatic initiatio of treatment system is made or each branch of thc stand-found to be inoperable for by gas treatment system any reason, REACTOR POMER shall be demonstrated OPERATIOH and fuel handling from unit'~nt s.

is permissible only during sg.3.4,.gg.g /4mc nay thc succeeding 7 days un1css t leas 41 such circuit is sooner made anual operability of OPERABLE, provided that the bypass valve for during such 7 days all filter cooling shall be active components of the demonstrated.

other tvo standby gas treatment trains shall bc c. Mhen one tra n o the perable. tandby g s treatm s stem bec es inope able th other t trains Rt5seo~ pet~~d$

tro+SLQ Ho.Af Q+g I sha 1 be demo to b OPERABLE trated vithin 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> d daily Pr1pogcg gfg,latr~ thereafter.

Aero~ g, I

4. If these conditions cannot be me : ~ovc~f og,~;<$ Q g~

Ac<I 0 tQ a. Suspend all fuel b~ .~g

+ssc~klats iw d Ca~qpg~g

~ gp~,Q~

• t" eE handling operations, core alterations, and activities vith the potential to drain any reactor vessel containing fue I-BF5 3.7/4.7-15 AMENDMENT ND. g77 Unit 2 WGC g

5 ccrlicp?4a w MAR 80 1980 4

cT~aH Place all reactors in 8 at least a HOT SHUTDOMH COHDITIOH vithin the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUTDOWNS COHDITIOH vi thin the folloving 24 hours.

3.7.C. S o C t 4.7.C. Seep da Co ta

1. Secondary containment integrity 1. Secondary containment shall bc maintained in the surveillance shall be reactor zone at all times performed as indicated cxccpt as specified ia belov:

3.7.C.2.

a. Secondary containment capability to maintain 1/4 inch of vatcr vacuum under ca~ vind

(< 5 mph) conditions vith a system leakage rate of not more than 12,000 cfm, shall be demonstrated at each refueling outage prior to rcfucling.

2. If reactor zone secondary 2. After a secondary containment integrity cannot containment violation is be maintained thc following determined, thc standby gas conditions shall be met: treatment system vill be operated immediately after

a. Suspend all fuel handling the affected zones arc operations, core altcra- isolated from the remainder tioas, and activities vith of the secondary thc potential to draia any containment to confirm its reactor vessel containing ability to maintain the fuel. remainder of the secondary containmcnt at 1/4-inch

b. Rcstorc reactor zone of water negative pressure secondary containmcnt under calm vind conditions.

integrity vithin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or place all reactors in at least a HOT SHUTDOMH COHDITIOH vithin thc next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> aad in a COLD SHUT-DOWN COHDITIOH vithin the folloving 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

BFH .7/4.7-16 AMENOMENT No. F77 .

Unit 2

Cl 0

MAR 80 tqso 4, ~ te

1. Except as specified in 1. At least once per year, r Specification 3.7.B.3 belov, the folloving conditions

~

) t'-0 36.43 all three trains of the shall be demonstrated.

standby gas treatment s stem shall be OPERABLE t all a. Pressure drop across times v en secondary the combined HEPA p

)

containment integrity is filters and charcoal required. adsorber banks is less than 6 inches of vater at a flov of 9000 cfm (g 10Ã).

b. The inlet heaters on each circuit are tested in accordance vith ANSI N510-1975, and are capable of an output of at least Sot', JHp44~i cog'e~ 4r (Q 40 kM.

4r Bfhf IS~ gqd c. Air distribution is uniform vithin 20K across HEPA filters

- and charcoal adsorbers.

Troppo'~ Sg S.$ ,6,3.2.

AMENDMENT ND. X '7 T BFH Unit 2 3.7/4.7-13 eGc 6 oF~

.7.F. 4.7.F.

SZRttell

1. The primary contaiame purge l. At least once every 18 system shall be OPE LE for mon , the pressure drop PURGIHG, except as pecified acr ss the combined HEPA in 3.7.F.2. f ters and charcoal orber banks shall be

a. The results f the in-place demonstrated to be lcss-,'.-

cold DOP d halogenated than 8.5 inches of vatei hydrocar n tests at design at system design flov flovs o HEPA filters and rate (g 10K).

chare 1 adsorber banks sha shov g 99K DOP removal a. The tests and sample an g 99K, halogenated hydro- analysis of Specifica-rbon removal when tested tion 3.7.F.1 11 be n accordance vith performed at east onc AHSI H510-1975 ~ pcr operati cycle or once eve 18 months,

b. The results of laborato vhichevc occurs first carbon sample analysi shall or aft 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of shov g 85K radioact e syst operation and methyl iodide remo 1 vhen fo ovtng significant tested in accord ce vith p ating, fire, or ASTM D3803. emical release in any ventilation zone comanmicating vith the

c. System flo rate shall be system.

showa to e within g 10K of desi flov vhen tcstcd b. Cold DOP testing shall in accordance vith be performed aftc each AHSI H510-1975 ~ complete or par al replacement of e HEPA If the provisions of 3.7.F.l.a, ~

filter bank after b, and c cannot be met, the any structu al mainte-system shall be declared nance on e system inoperable. The provisions of "

housing.

Technical Specification 1.C.1 do not apply. PURGIHG may coa- c. Halog tcd hydrocarboa tiaue using the Standby Gas tes shall be Treatment System. pcr ormed after each complete or partial

~ a. e - ch pr ry conta replacement of the ment isolation valves asso- charcoal adsorber bank ciated vith PURGIHG may be or after any structural open during, the RUH mode maintenance on the for a 24-hour period after system housing.

entering the RUH mode and/or for a 24<<hour period prior ~< ~HsfICicak'so~ Qr t:h~gqg to entering the SHUTDOMH 4~ am i~~ ~~I ~

mode. The OPERABILITY of.

gg@O~ pg I BFK-Unit 2

. 3.7/4.7-21 ~1 Ny.

Vr.

UNIT 3 CURRENT TECHNICAL SPECIFICATION MARKUP

u PCCggiC'a Z, lo

+> 3 0 1990

l. Except as specified in At least once per year, Specification 3.7.B.3 belov, the folloving conditions

+g ~<<' >all three trains of the shall be demonstrated.

standby gas treatment s stem shall be OPERABLE at all a. Pressure drop across times v en secondary the combined HEPA containment integrity is filters and charcoal required. adsorber banks is less than 6 inches of vater at a flov of 9000 cfm (g 10K).

b. The inlet heaters on each circuit are tested in accordance vith AHSI H510-1975, and are capable of an ac gusfigcahon foe output of at least Cho~gcs Pr 5~ t 5 Ts 40 kM.

5ccvi ~

c. Air distribution is uniform vithin 20K across HEPA filters and charcoal adsorbers.

Z y~eP Se s.e.q.z,~

AMENDMENTNa. X4 $

BFI 3.7/4.7-13 unit 3 PAGE A 0'

2. a. The results of the in-place 2. a. e tests and sample cold DOP and halogenated analysis of hydrocarbon tests at g 10Z Specification 3.7.B.2 design flow on HEPA filters shall be performed at and charcoal adsorber banks least once per operating shall show g99Z DOP removal cycle or once every and g99Z halogenated 18 months whichever hydrocarbon removal when occurs first for standby tested in accordance with service or after every AHSI H510-1975. 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of system operation and following significant painting, fire, or chemical release in any ventilation zone communicating with the system.

b. The results of laboratory b. Cold DOP testing shall carbon sample analysis be performed after shall show g90Z radioactive each complete or partial methyl iodide removal when replacement of the HEPA tested in accordance with filter bank or after any ASTM D3803. structural maintenance on the system housing.

c. System shall be shown to c. Halogenated hydrocarbon operate within glOX design testing shall be flow. performed after each complete or partial replacement of the charcoal adsorber bank or after any structural maintenance on the system housing.

BPH 3.7/4.7-14 NENO<<Ee NO I8 g Unit 3

CO MME S S MS 5f'ec>f'cuban 3. C.Q 3 ~ 3 0 I90 fAePOSeg /CA'on D ~ ~

SR3 <.9.3',l /N2.

operated ota of at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> every month.

e. Test sealing of gaskets On ~ at&4 or 5i~MlR r ho ing do s shall in'god ~ianna) be pcrfo ed uti izing ch ical moke ge era-tors duri each t st perfo ed fr compli ce v th Spec ficatio 4.7. .2.a and Specification .7.B.2.a.

5g 3'.6 v h

3. From and after the date that a. ce pcr one train of the standby gas automatic initiation of treatment system is made or each branch of t e stand-found to be inoperable for by gas treatment system al tra~

~*

any reason, REACTOR POWER e emoqs OPERATIOH and fuel handling rom ca unit& contro is permissible only during 5R ~.<.V.~V ~ eoe&f thc succeeding 7 days unless such circuit is sooner made manual operability o OPERABLE, provided that the bypass valve for during such 7 days all filter cooling shall be active components of thc demonstrated.

other tvo standby gas treatment trains shall be C~ onc train of the operable. st dby g s tre ment sys em bec mes i perable iloys~A Nog g gr~,,M 46 n~ the ther t o tra s 04 C4E ~ I shall be d nstra ed

~z to be PERAB vithx 2 WHonC I hours dail hereafter.

4. If these conditions cannot bc mct:

a. Suspend all fuel <Ihg IH~a oaf 4 lrrRdi'afcd Rtbh'andling operations, ~en bligh ih Wc scco~y co&;hnehg C.>E core alterations, and ~< '"$ ~<F ift,7FRtlTXCWS, Or ggri ~~

activities vith the OT't Rlt's potential to drain any reactor vessel containing fue s~Miale lq Al BFH 3.7/4. 7-15 AMENDMENT No. 74 g Unit 3

4

b. Place all reactors in RChon at least a HOT SHUTDOWH 6 COHDITIOH within the next 5'uSfjke~ +, (~~peg 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUTDOWH COHDITIOH within 4< ~n) /5 75 3 .4 . Q. I the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

3.7.C. Seconda o a nme 4.7.C. Seep da Containment

• 1. Secondary containment integrity 1. Secondary containment shall be maintained in the surveillance shall be reactor zone at all times performed as indicated except as specified in below:.

3.7.C.2.

a. Secondary containment

• LCO not applicable until )ust capability to maintain prior to loading fuel into 1/4 inch of water vacuum the Unit 3 reactor vessel, under calm wind provided the Unit 3 reactor (< 5 mph) conditions zone is not required for with a system inleakage secondary containment rate of not more than integrity for other units. 12,000 cfm, shall be demonstrated at each refueling outage prior to refueling.

2. If reactor zone secondary 2. After a secondary containment integrity cannot containment violation is be maintained the following determined, the standby gas conditions shall be met: treatment system will be operated immediately after

a. Suspend all fuel handling the affected zones are operations, core altera- isolated from the-remainder tions, and activities with of the secondary the potential to drain any containment to confirm its reactor vessel containing ability to maintain the fuel. remainder of the secondary containment at 1/4-inch

b. Restore reactor zone of water negative pressure secondary containment under calm wind conditions.

integrity within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, or place all reactors in at least a HOT SHUTDOWH COHDITIOH within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in a COLD SHUT-DOWH COHDITIOH within the following 24 hours.

BFH ENDMEHT NO. 159 Unit 3 was ~op ~

3.7.F. 4.7.F.

1. The primary containment purge 1. At least once every 18 system shall be OPERABLE for months, the pressure dro PURGIHG, except as specified across the combined HEPA in 3.7.F.2. filters and charcoal adsorber banks shall be

a. The results of the in-place demonstrated to bc less cold DOP and halogenated than 8.5 inches of vater hydrocarbon tests at design at system design flov flows on HEPA filters and rate (g lOZ).

charcoal adsorber banks shall shov g 99K DOP removal a. The tests and sample and g 99% halogenated hydro- analysis of Specifica-carbon removal vhen tcstcd tion 3.7.F.l shall be in accordance vith performed at least once AHSI H510-1975. per operating cycle or once every 18 months,

b. The results of laboratory whichever occurs first carbon sample analysis shall or after 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of shov g 85K radioactive system operation and methyl iodide removal vhcn folloving significant tested in accordance vith painting, fire, or AS'3803. chemical release in any ventilation zone coamunicating vith the

c. System flov rate shall be systems sham to be vithin g 10X of design flov vhen tested b. Cold DOP testing shall in accordance vith be performed after ea AHSI 5510-1975 ' complete or partial replacement of thc HEP

~ If the provisions of 3.7.P,l.a~ filter bank or after b, and c cannot be met, the any structural mainte-system shall be declared nance an the system inoperable. The provisions of housing.

Technical Specification 1.C.1 do not apply. PURCINC may con>> c. Halogenated bydrocarbo tinue using the Standby Caa testing shall be Treatment System. perfarmed after each complete ar partial

3. a. The 18-inch primary contain- replacement of the ment isolatian valves asso- charcoal adsorber bank ciated vith PURGIHG may be or after any atructura open during the RUH mode maintenance on the f'r a'4-hour period after system housing.

entering the RUE mode and/or for a 24-hour period prior to catering the SHUTDOWI The OPERABILITY of 4 c~ I'5

%is QPgqgp~

~~<~ S4

+~ $ w~

mode.

3.7/4.7-21 amo~ur s0. EBS BPK \

Unit S I

t BFN ISTS ADMINISTRATIVE CHANGES Al JUSTIFICATION 3.6.4.3 -

FOR CHANGES STANDBY GAS TREATMENT SYSTEM Reformatting and renumbering are in accordance with the BWR Standard Technical Specifications, NUREG 1433. As a result the Technical Specifications should be more readily readable, and therefore, understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is done to make consistent with NUREG-1433. During ISTS development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or interpretational) to the Technical Specifications. Additional information has also been added to more fully describe each subsection. This wording is consistent with the BWR Standard Technical Specifications, NUREG-1433. Since the design is already approved, adding more detail does not result in a technical change.

A2 The technical content of this requirement is being moved to Section 5.0 of the proposed Technical Specifications in accordance with the format of the BWR Standard Technical Specifications, NUREG 1433. Any technical changes to this requirement will be addressed within the content of proposed Specification 5.5.7. A surveillance requirement (proposed .SR 3.6.4.3.2) is added to clarify that the tests of the Ventilation Filter Testing Program must also be completed and passed for determining operability of the SGT System. Since this is a presentation preference that maintains current requirements, this change is considered administrative.

A3 The description of the signal used to automatically initiate the SGT System "actual or simulated initiation signal" has been added for clarity. This is consistent with the BWR Standard Technical Specifications, NUREG 1433, and no change is intended.

A new ACTION is proposed (ACTION D) which directs entry into LCO 3.0.3 if two or more required standby gas treatment subsystems are inoperable in Modes 1, 2, or 3. This avoids confusion as to the proper action in Modes 1, 2, or 3 and simultaneously handling fuel, conducting CORE if ALTERATIONS, or operations with the potential for draining the reactor vessel. Since the proposed ACTION effectively results in the same action as the current specification, this change is considered administrative.

A5 The Frequency for verifying SGTS automatic initiation has been changed to 18 months from once per operating cycle. The BFN operating cycle is currently defined as 18 months. As such this is a change in presentation only and is therefore administrative.

BFN-UNITS 1, 2, 5 3 Revision 0 PAcs I or~

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.4.3 - STANDBY GAS TREATMENT SYSTEM TECHNICAL CHANGES - MORE RESTRICTIVE This change requires the movement of irradiated fuel in secondary containment and CORE ALTERATIONS to be "Immediately" suspended secondary containment is inoperable.

if In addition, action must be "Immediately" initiated to suspend operations with the potential to drain the reactor vessel in this Condition. The current specification does not establish a time limit to suspend these activities.

Immediately suspending these activities minimizes the probability of a fission product release if a reactivity event occurs while the secondary containment is inoperable. Also, immediately initiating action to suspend operation with the potential to drain the reactor vessel will minimize the potential for. reactor vessel draindown and subsequent potential for fission release. Imposing a time limit to suspended these activities is a more restrictive change.

CTS 4.7.B.2.d requires each train to be operated a total of at least 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> each month. Proposed SR 3.6.4.3. 1 requires each train to be.

operated continuously for 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. As such, the proposed SR is considered more restrictive.

TECHNICAL CHANGES - LESS RESTRICTIVE "Generic" LA1 Details on methods of testing gasket seals for housing doors has been deleted. This type of detail will be retained in plant procedures and/or system operating instructions.

LA2 Details on the method of performing Standby Gas Treatment system surveillance requirements have been relocated to plant procedures.

Changes to the procedure will be controlled by licensee controlled programs.

"Specific" L1 The proposed change will delete the requirement to test the other SGT subsystems when one subsystem is inoperable. The requirement for demonstrating operability of the redundant subsystems was originally chosen because there was a lack of plant operating history and a lack of sufficient equipment failure data. Since that time, plant operating experience has demonstrated that testing of the redundant subsystems when one subsystem is inoperable is not necessary to provide adequate assurance of system operability.

This change will allow credit to be taken for normal periodic surveillances as a demonstration of operability and availability of the BFN-UNITS 1, 2, 5 3 Revision 0 PAGE

JUSTIFICATION FOR CHANGES BFN ISTS 3.6.4.3 - STANDBY GAS TREATMENT SYSTEM remaining components. The periodic frequencies specified to demonstrate operability of the remaining components have been shown to be adequate to ensure equipment operability. As stated in NRC Generic Letter 87-09, "It is overly conservative to assume that systems or components are inoperable when a surveillance requirement has not been performed. The opposite is in fact the case; the vast majority of surveillances demonstrate the systems or components in fact are operable." Therefore, reliance on the specified surveillance intervals does not result in a reduced level of confidence concerning the equipment availability.

Also, the current Standard Technical Specifications (STS) and, more specifically, all the Technical Specifications approved for recently licensed BWRs accept the philosophy of system operability based on satisfactory performance of monthly, quarterly, refueling interval, post maintenance or other specified performance tests without requiring additional testing when another system is inoperable (except for diesel generator testing, which is not being changed).

L2 An alternative is proposed to suspending operations if a SGT subsystem cannot be returned to OPERABLE status within seven days, and movement of irradiated fuel assemblies, CORE ALTERATIONS, or operations with the potential for draining the reactor vessel are being conducted. The alternative is to initiate two OPERABLE subsystems of SGT and continue to conduct the operations. Since two subsystems are sufficient for any accident, the risk of failure of the subsystems to perform their intended function is significantly reduced if they are running. This alternative is less restrictive than the existing requirement. However, the proposed alternative ensures that the remaining subsystems are Operable, that no failures that could prevent automatic actuation have occurred, and that any other failure would be readily detected. This change is consistent with NUREG-1433.

L3 The Required Actions of C and E. I have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE I, 2, or 3, the fuel movement is independent of reactor operation and the inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown. By adding an exception to LCO 3.0.3 for the failing to suspend irradiated fuel movement, an LCO 3.0.3 required reactor shutdown is avoided in MODE I, 2, or 3. However, the plant would still be required to shutdown per proposed Required Actions B. 1 and B.2 in addition to suspending fuel movement per Required Actions C. I and E. l. However, this shutdown is considered less restrictive since Required Action B. 1 allows the plant to be in Hot Shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> versus Hot Standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> as required by CTS 1.0.C. l.

Both CTS and the proposed Required Action B.2 require the plant to be in Cold Shutdown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

BFN-UNITS I, 2, 8. 3 Revision 0 PAGE~OF~

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JUSTIFICATION FOR CHANGES CTS 3.7.F/4.7.F - PRINRY CONTAINMENT PURGE SYSTEN RELOCATED CHANGES Rl CTS .3.7.F. 1 & 2 and 4.7.F requirements have been relocated to the Technical Requirements Manual (TRM). The Primary Containment Purge System is normally isolated and normally not required to be functional during power operation. It does provide the preferred exhaust path for purging the primary containment; however, the SGTS can be used to perform the equivalent function. The supply and isolation valves are depended on to function properly for containment isolation, which is covered in proposed BFN ISTS Section 3.6.1.3, Primary Containment Isolation Valves.

BFN-UNITS 1, 2, & 3 Revision 0

Enclosure III Volume 7

'l TABLE OF CONTENTS Section ~Pa r~o 8 2.0 SAFETY LIMITS (SLs) 8 2.0 X.,-

8 2.1.1 Reactor Core SLs 8 2.0 8 2.1.2 Reactor Coolant System (RCS) Pressure SL 8 2.0.~7 8 3.0 LIMZTZNG CONDITION FOR OPERATION (LCO) APPLICABILITY 830"1 8 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY ~ '8 "3'. 0-1P 8 3.1 REACTIVITY CONTROL SYSTEMS 8 3,1 3, 8 3.1.1 SHUTDOWN MARGZN (SDM) . . . . . . . ~ 8 3.1-1 8 3.1 2 Reactivity Anomalies 8 3.>> 0 8

~

3. 1.3 Control Rod OPERABILITY .'8'. 1 13

,8 3.1.4 Control Rod Scram Times .'" '8 3 ~ I-?2 Ba 3.1.5 Control Rod Scram Accumulators 8 3>>1" 29 3.'. 6 Rod Pattern Control .. 8'".3.-34' 3'"-39' 3.1.7 Standby Liguid Control (SLC) System ~ ~

3.1.8 Scram Discharge Volume (SDV) Vent and Dra in Valves 3. 1-46 8 3.2 POWER DISTRIBUTION LIMITS 8 3.2-1 8 3.2. 1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) 8 3.2-1 '

8 .3 ~ 2.2 MINIMUM CRITICAL POWER RATIO (MCPR) 3 '-4 8 3.2.3 LZNEAR HEAT GENERATION RATE (LHGR) 8 3.2-9 8 3.2.4 Average Power Range Monitor (APRM)

Gain and Setpoints 8;3 ~ 2 12

'

8 3.3 INSTRUMENTATION 8 3.3-1 8 3.3.1.1 Reactor Protection System (RPS)

Instrumentation 8 3. 3-1 8 3 ~ 3 ~ 1'.2 Source Range Monitor (SRM) Znstrumentation 8 "3.3 33 8 3.3.2.1 Control Rod Block Instrumentation '8 3. 3.~4?

8 3.3.2.2 Feedwater and Main Turbine Trip Instrumentation 8 3.3-53 3.3.3.1 Post Accident Monitoring (PAM)

Instrumentation 8 3.3-60

.8 3.3.3.2 Backup Control System 8 3 '-,71 8 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT)

Instrumentation 8 3.3-80 B 3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)

Instrumentation 8 3.3-89 3.3.5.1 Emergency Core Cooling System (ECCS)

Instrumentation 8 3.3-98 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation 8 3.3-135 3.3.6.1 Primary Containment Isolation Instrumentation 8 3.3-143 3.3.6.2 Secondary Containment Isolation Instrumentation . 8 3.3-165 3.3.7.1 Control Room Emergency Ventilation (CREV)

System Instrumentation 8 3.3-176 8 3.3.8 1 Loss of Power (LOP) Instrumentation 8 3.3-188 Reactor Protection System (RPS) Electric

~

8 3.3.8.2 3.3-196 Power Monitoring 8 BFN Unit 2

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Section ~Pa e No.

B 3.4 REACTOR COOLANT SYSTEM (RCS) . . ~ B 3. 4-1 B 3.4.1 Recirculation Loops Operating B 3.4-1 B 3.4.2 Jet Pumps B 3.4-9 B 3.4.3 Safety/Relief Valves (S/RVs) B 3.4-14 B 3.4.4 RCS Operational LEAKAGE B 3.4-19 B 3.4.5 RCS Leakage Detection Instrumentation B 3.4-25 B 3.4.6 RCS Specific Activity B 3. 4-31 3.4.7 Residual Heat Removal (RHR) Shutdown B

Cooling System- Hot Shutdown B 3 '-35 3 '.8 Residual Heat Removal (RHR) Shutdown Cooling System Cold Shutdown B 3 '-40 3.4.9 RCS Pressure and Temperature (P/T) Limits B 3.4-45 3.5 EMERGENCY CORE COOLING 'SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5-1 B 3.5 ' ECCS Operating B 3.5-1 B 3.5.2 ECCS Shutdown ~ . ~ ~ . ~ ~ ~ B 3.5-18 B 3.5.3 RCIC System B 3.5-24 B 3.6 CONTAINMENT SYSTEMS B 3 '-1

'-1 B 3.6. 1. 1 Primary Containment B 3 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 Temperature B 3.6-28 3.6.1.5 Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6-31 B 3 ~ 6. 1.6 Suppression Chamber-to-Drywell Vacuum Breakers B 3.6-37 B 3.6.2.1 Suppression Pool Average Temperature B 3.6-43 B 3.6.2.2 Suppression Pool Water Level B 3.6-49 B 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling o ~ t ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 3.6-52

'B 3.6.2.4 Residual Heat Removal (RHR) Suppression Pool

'Spray B 3.6-57 B 3.6.2.5 Residual Heat Removal (RHR) Drywel1 Spray B 3.6-75 B 3.6.2.6 Drywell-to-Suppression Chamber Differential Pressure e ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ I' ~ ~ ~ ~ ~ B 3.6-67 B 3.6.3.1 Containment Atmosphere Dilution (CAD) System B 3.6-70 B 3.6.3.2 Primary Containment Oxygen Concentration B 3.6-75 B 3.6.4 ' Secondary Containment B 3.6-78 B 3.6.4.2 Secondary Containment Isolation Valves ('SCIVs) B 3.6-83 B 3.6.4.3 Standby Gas Treatment (SGT) System B 3.6-89 B 3.7 PLANT SYSTEMS . . . . . . . . . ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 3~7 1 B 3.7.1 Residual Heat Removal Service Water (RHRSW) System i e ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 3.7-1 3.7.2 Emergency Equipment Cooling Water (EECW) System and Ultimate Heat Sink (UHS) 3~7 7 3.7.3 Control Room Emergency Ventilation (CREV)

S ystem B 3.7-12 B 3.7.4 Control Room Air Conditioning (AC) System B 3.7-19 B 3'. 7. 6 Main Condenser Offgas B 3.7-30 B 3.7.7 Main Turbine Bypass System B 3.7-24 B 3.7 ' Spent Fuel Storage Pool Water Level B 3.7-28 BFN Unit 2 4

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~Sectio Pacae No.

B 3.8 ELECTRICAL POWER SYSTEMS B 3.8-1 B'.8.1 AC Sources -Operating B 3'. 8-1 B 3. 8.'2 AC Sources -'Shutdown ~ ~ ~ ~ ~ ~ ~ ~ ~ B 3.8-28 B 3.8.3 Diesel FuelOil, Lube Oil, and Starting Air B 3.8-35 B 3.8.4 DC Sources Operating B 3.8-42 B 3.8.5 DC Sources -'Shutdown B 3'. 8-51 B 3.8.6 Battery Cell 'Parameters B 3.8-55 B 3.8.7 Inverters -Operating B 3.8-62 B 3.8.8, Inverters Shutdown ~ B 3.8-73 B. 3.9 REFUELING OPERATIONS B 3.'9-1 B 3.9.1 Refueling. Equipment Interlocks B: 3.9-1 B 3.9.2 Refuel Position One-Rod-Out Interlo'ck B 3.9-5 B 3.9.'3. Control Rod Position B: 3.9-9 B .3.9.4 Control Rod Position .Indication B 3.9-12

,B'.9.5 Control Rod OPERABILITYRefueling B 3.9-16 B 3~9~6 Reactor Pressure Vessel (RPV) Water Level B 3 '-19

,B 3.9.7' Residual Heat Removal;(RHR) High Water Level B 3.9-22.

3 ~ 9.8. Residual Heat Removal (RHR) Low Water Level,. B 3.9-26

.B 3.10 SPECIAL 'OPERATIONS ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ . ~ ~ B 3. 10-1 B 3 ~ 10 ~ 1 Inservice Leak and Hydrostatic Testing Operation 'B 3.10-1 B 3.10.2 Reactor Mode, Switch Interlock Testing B 3.10-6 B 3.10.3 Single Control Rod Withdrawal' Hot Shutdown B 3.10-11 B 3.10.4 Single Control Rod 'Withdrawal Cold Shutdown B 3.10-16 B 3.10.5 Single Control Rod Drive (CRD)

Removal Refueling B 3.10-21

'B 3.10.6 Multiple Control Rod,Withdrawal -Refueling B 3.10-26 3'.10-29 B 3. 10.'7 Control Rod'esting-Operating B B 3.10.8 SHUTDOWN MARGIN (SDM) Test Refueling B 3'.10-33 BFN.

Unit 2 g hduncanhulbasa s.toe

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Reactor Core SLs B 2.1.1 B 2.0 SAFETY LIMITS (SLs) 8 2. 1. 1 Reactor Core SLs BASES BACKGROUND GDC 10 (Ref. 1) requires, and 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 the HCPR is not less than the limit specified in Specification 2. 1. 1.2 for General Electric Company (GE) 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. Although some corrosion or use related cracking may occur during the life of the cladding, fission product migration from this source is incrementally cumulative and continuously measurable. Fuel cladding perforations, however, can result from thermal stresses, which occur from reactor operation significantly above design conditions.

Mhile fission product migration from cladding perforation is just as measurable as that from use related cracking, the thermally caused c'/adding perforations signal 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 would produce onset of transition boiling

(,i.e., NCPR = 1.00). These conditions represent a significant departure from the condition intended by design for planned operation. The NCPR fuel cladding integrity SL ensures that during normal operation and during abnormal operational transients, at least 99.9% of the fuel rods in the core do not experience transition boiling.

{continued)

BFN-UNIT 2 B 2.0-1 Amendment

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Reactor Core SLs B 2.

1.1 BACKGROUND

Operation above the boundary of the nucleate boiling regime (continued) could result in excessive c1adding temperature because of the onset of transition boiling and the resultant sharp reduction in heat transfer coefficient. Inside the steam film, high cladding temperatures are reached, and a cladding-water (zirconium-water) reaction may take place.

This chemical reaction results in oxidation of the fuel cladding to a structurally weaker form. This weaker form may lose its integrity, resulting in an uncontrolled release of activity to the reactor coolant.

APPL ICABL'E The fuel cladding, must not sustain damage as a result of SAFETY ANALYSES normal operation and abnormal operational transients. The reactor core SLs are established to preclude violation of the fuel design criterion that an MCPR limit is to be established, such that at least 99.9% of the fuel rods in the core would not 'be expected to experience the onset of transition boiling.

The Reactor Protection System setpoints (LCO 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

'oolant System water level, pressure, and THERMAL POWER level that .woul'd result in reaching the MCPR limit.

2. 1. 1. 1 Fuel Claddin Inte rit GE critical power correlations are applicable for all critical power calculations at pressures ~ 785 psig and core flows ~ 10% of rated flow. For operation at low pressures or low flows, another basis is used, as follows:

The static head across the fuel bundles due onl'y to elevation effects from liquid only in the channel, core bypass region, and annulus at zero power, zero flow is approximately 4.5 psi. At all operating conditions, this pressure differential is maintained by the bypass region of the core and the annulus region of the vessel.

The elevation head provided by the annulus produces natural circulation flow conditions which have balancing pressure head and loss terms (continued)

BFN-UNIT 2 B 2.0-2 Amendment

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Reactor Core SLs B 2.1.1 BASES inside the core shroud. This natural circulation principle maintains a core plenum to plenum pressure drop of about 4.5 to 5 psid along the natural circulation flow line of the P/F operating map. In the range of, power levels of interest, approaching 25% of rated power below which thermal margin monitoring is not required, the pressure drop and density head terms tradeoff for power changes such that natural circulation flow is nearly independent of reactor power.

This characteristic is represented by the nearly vertical portion of the natural circulation line on the P/F operating map. Analysis has shown that the hot channel flow rate is )28,000 lb/hr in the region of operation with power -25% and core pressure drop of about 4.5 to 5 ps,id. Full scale ATLAS test data taken at pressures from 14.7 psia to 800 psia indicate that the fuel assembly critical power at 28,000 lb/hr is approximately 3 NWt. With the design peaking factors, this corresponds to a core thermal power of more than 50%. Thus operation up to '25% of rated power with normal natural circulation available. is conservatively acceptable even if reactor pressure is equal to or below 800 psia (the limit of the range of applicability of GETAB/GEXL for GE fuel). If reactor power is

-significantly less than 25% of rated (e.g., below 10% of rated), the core flow and the channel flow supported by the available driving head may be less than 28,000 lb/hr (along the lower portion of the natural circulation flow characteristic on the P/F map). However, the critical power that can be supported by the core and hot channel flow with normal natural circulation paths available remains well above the actual power conditions.

The .inherent characteristics of BWR natural circulation make power and core flow follow the natural circulation line as long as normal water level is maintained.

(continued)

BFN-UNIT 2 B 2.0-3 Amendment

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Reactor Core SLs 8 2.1.1 APPLICABLE 2. l. l. I Fuel Claddin Inte rit (continued)

SAFETY ANALYSES Thus, operation with core thermal power below 25% of rated without thermal, margin surveillance is conservatively acceptable even for reactor operations at natural circulation. Adequate fuel thermal margins are also maintained without further surveillance for the low power conditions that would be present if core natural circulation is below 10% of rated flow (the limit of applicability of the GETAB/GEXL correlations for GE fuel).

2.1.1.2 HCPR The fuel cladding integrity SL is set such that no fuel damage is calculated to occur Since the parameters that if the result limit is not violated.

in fuel damage are not directly observable during reactor operation, the thermal and hydraulic conditions that result in the onset of transition boiling have been used to mark the beginning of the region in which fuel damage could occur. Although recognized that the onset of transition boiling would not it is result in damage to BWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit. However, the uncertainties in monitoring the core operating state and in the procedures used to cal'culate the critical power result in an uncertainty in the value of the critical power. Therefore, the fuel cladding integrity SL is defined as the critical power ratio in the limiting fuel assembly for which more than 99.9% of the fuel rods in the core are expected to avoid boiling transition, considering the power distribution within the core and all uncertainties.

The HCPR SL is determined using a statistical model that combines all the uncertainties in operating parameters and the procedures used to calculate critical power. The probability of the occurrence of boiling transition is determined using the approved General Electric Critical Power correlations. Details of the fuel cladding integrity SL calculation are given in Reference 2. Reference 2 also includes a tabulation of the uncertainties used in the determination of the MCPR SL and of the nominal values of the parameters used in the NCPR SL statistical analysis.

(continued)

BFN-UNIT 2 B 2.0-4 Amendment

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Reactor Core SLs 8 2.1.1 BASES APPLICABLE 2. 1. 1.3 Reactor Vessel Water Level SAFETY ANALYSES (continued) During MODES 1 and 2 the reactor vessel water level is required to be above the top of the active fuel to provide core cooling capability. With fuel in the reactor vessel during periods when the reactor is shut down, consideration must be given to water level requirements due to the effect of decay heat. If the water level should drop below the top of the active irradiated fuel during this period, the ability to remove decay heat is reduced. This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that the water level becomes ( 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 can be monitored and to also provide adequate margin for effective action.

SAFETY LIMITS The reactor core SLs are established to protect the integrity of the fuel clad barrier to the release of radioactive materials to the environs. SL 2.1. l. 1 and SL 2.1.. 1.2 ensure that the core operates within the fuel design criteria. SL 2. 1. 1.3 ensures that the reactor vessel water level is greater than the top of the active irradiated fuel in order to prevent elevated clad temperatures and resultant clad perforations.

APPLICABILITY SLs 2. l. 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 potential Y IOLATION S for radioactive releases in excess of 10 CFR 100, "Reactor Site Criteria," limits (Ref. 3). Therefore, it is required to insert all insertable control rods and restore compliance with the SLs within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time ensures that the operators take prompt remedial action and also ensures that the probability of an accident occurring during this period is minimal.

(continued)

BFN-UNIT 2 B 2.0-5 Amendment

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Reactor Core SLs B 2.1.1

'BASES (continued)

REFERENCES l. 10 CFR 50, Appendix A, GDC 10.

2. GE SIL No. 516, Supplement 2, January 19, 1996.

3. 10 CFR 100.

BFN-UNIT 2 B 2.0-6 :Amendment

0 RCS Pressure SL 8 2.1.2 B 2.0 SAFETY LIHITS (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. The RCS then serves .as the primary barrier in preventing the release of fission products into the atmosphere. Establishing an upper limit on reactor steam dome pressure ensures continued RCS integrity. Per 10 CFR. 50, Appendix A, GDC 14, "Reactor Coolant Pressure Boundary," and GDC 15, "Reactor Coolant System Design" (Ref. 1), the reactor coolant pressure boundary (RCPB) shall be designed with sufficient margin to ensure that the design conditions are not exceeded during normal operation and 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 ASHE .

Code (Ref. 2). To 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. 10. 1-, "Inservice Leak and Hydrostatic Testing Operation." Following inception of unit operation, RCS components shall be pressure tested in accordance with the requirements of ASHE Code,Section XI (Ref. 3).

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

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

(continued)

BFN-UNIT 2 B 2.0-7 Amendment

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RCS Pressure SL B 2.1.2 BASES (continued)

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

The RCS pressure SL has been selected such that it is at a

,pressure below which it can be shown that the integrity of the system is not endangered. The reactor pressure vessel is designed to Section III of the ASHE, Boiler and Pressure Vessel Code, 1965 Edi,tion, including Addenda through the summer of 1965 (Ref. 5), which permits a maximum pressure transient of 110%, 1375 psig, of design pressure 1250 psig.

The SL of 1325 psig, as measured in the reactor steam dome is equival'ent to 1375 psig at the lowest elevation of the RCS. The RCS is designed to the USAS Nuclear Power Piping Code, Section B31. 1, 1967 Edition (Ref. 6), and the additional requirements of GE design and procurement specifications (Ref. 7) which were implemented in lieu of the outdated B31 Nuclear Code Cases - N2, N7, N9, and N10, for the reactor recirculation piping, which permits a maximum pressure transient of 120% of design pressures of 1148 psig for suction piping and 1326 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 pressure allowable in the RCS pressure vessel under the ASHE Code,Section III, is 110% of design pressure. The maximum transient pressure allowable in the RCS piping, valves, and fittings is 120% .of design pressures of 1148 psig for suction piping and 1326 psig for discharge piping. Mhen the 20%. allowance (230 and 265 psig) allowed by USAS Piping Code, Section B31. 1, for pressure transients is added to the design pressures, transient pressure limits of 1378 and 1591 psig are established. The most limiting of these allowances is the 110% of design pressure for the RCS pressure vessel; therefore, the SL on maximum allowable RCS pressure is established at 1325 psig as measured at the reactor steam dome.

APPLICABILITY SL 2. 1.2 applies in all NODES.

(continued)

BFN-UNIT 2 B 2.0-8 Amendment

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RCS Pressure SL B 2.1.2 BASES (continued)

SAFETY LIHIT Exceeding the RCS pressure SL may cause immediate RCS VIOL'ATI ONS failure and -create a,potential for radioactive releases, in excess of 10 CFR 100, "Reactor Site Criteria,'" limits (Ref. 4). Therefore,, it is required to insert .all insertable control rods and restore compliance with the SL within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time ensures that the operators take prompt .remedial action and also assures that the probabil.i.ty of an accident occurring during this period is minimal.

0 REFERENCES l. 10 CFR 50, Appendix A, GDC 14, GDC 15, and GDC 28.

2. ASHE, Boiler and Pressure Vessel Code, Section III, Article NB-7000.

3. ASHE, Boiler and Pressure Vessel Code,Section XI, Article IW-5000.

'4. 10 CFR 100.

5. ASHE, Boiler and Pressure Vessel Code,:Section III, 1965 Edition, Summer of 1965 Addenda.

6. ASHE, USAS, Nuclear Power Piping Code, Section B31.1, 1967 Edition.,

7. BFN General Electric Design Specification 22A1406, "Pressure .Integrity of Piping and Equipment Pressure.

Parts," Revision 2, April 28, 1970.

BFN-UNIT 2 B 2.0-9 Amendment

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LCO Applicability B 3.0 BASES LCOs LCO 3.0.1 through LCO 3.0.7 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

LCO 3.0.1 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 unit is in the MODES or other specified conditions of the Applicability statement of each Specification).

LCO 3.0.2 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:

a. Completion of the Required Actions within the specified Completion Times constitutes compliance with a Specification; and

b. Completion of the Required Actions is not required when an LCO is met within the specified Completion,,

Time, unless otherwise specified.

There are two basic types of Required Actions. The first type of Required Action specifies a time limit in which the LCO 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 is 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 (continued)

BFN-UNIT 2 B 3.0-1 Amendment

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LCO Applicability B 3.0 BASES LCO 3.0.2 ACTIONS.) The second type of Required Action specifies the (continued) remedial measures that permit continued operation of the unit that is not further restricted by the Completion Time.

In this case, compliance with the Required Actions provides an acceptable level of safety for continued operation.

Completing the Required Actions is not required when an LCO is met or is no longer applicable, unless otherwise stated in the individual Specifications.

The nature of some Required Actions of some Conditions necessitates that, once the Condition is entered, the Required Actions must be completed even though the associated Conditions no longer exist. The individual LCO's ACTIONS specify the Required Actions where this is the case.

An example of this is in LCO 3.4.9, "RCS Pressure and Temperature Limits."

The Completion Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The reasons for intentionally relying on the ACTIONS include, but are not limited to, performance of Surveillances, preventive maintenance, corrective maintenance, or investigation of operational problems. Entering .ACTIONS for these reasons must be done in a manner that does not compromise safety. Intentional entry into ACTIONS should not be made for operational convenience. Alternatives that would not result in redundant equipment being inoperable should be used instead.

Doing so limits the time both subsystems/divisions of a, safety function are inoperable and limits the time other conditions exist which result in LCO 3.0.3 being entered.

Individual Specifications may specify a time limit for performing an SR when equipment is removed from service or bypassed for testing. In this case, the Completion Times of the Required Actions are applicable when this time limit expires, if the equipment remains removed from service or bypassed.

When a change in MODE or other specified condition is required to comply with Required Actions, the unit may enter a MODE or other specified condition in which another Specification becomes applicable. In this case, the Completion Times of the associated Required Actions would (continued)

BFN-UNIT .2 B 3.0-2 Amendment

LCO Applicability B 3.0 LCO 3.0.2 apply from the point in time that the new Specification (continued) becomes applicable and the ACTIONS Condition(s) are entered.

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 and Completion Time is not met and no other Condition applies; or

b. The condition of the uni't is not specifically addressed by the associated ACTIONS. This means that no combination of Conditions stated in the ACTIONS can be made that exactly corresponds to the actual condition of the unit. Sometimes, possible combinations of Conditions are such that entering LCO 3.0.3 is, 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 NODE or other specified condition when operation cannot be maintained within the limits for safe operation as defined by the LCO and its ACTIONS. It is not intended to be used as an operational convenience that permits routine voluntary removal of redundant systems or components from service in lieu of other alternatives that would not result in redundant systems or components being inoperable.

Upon entering LCO 3.0.3, I hour is allowed to prepare for an orderly shutdown before initiating a change in unit operation. This includes time to permit the operator to coordinate the reduction in electrical generation with the load dispatcher to ensure the stability and availability of the electrical grid. The time limits specified to reach lower NODES of operation permit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rate and within the capabilities of the unit, assuming that only the minimum required equipment is OPERABLE. This reduces thermal stresses on components of the Reactor Coolant System and the potential for a plant upset that could challenge safety systems under (continued)

BFN-UNIT 2 B 3.0-3 Amendment

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LCO Applicability B 3.0 BASES LCO 3.0.3 conditions to which this Specification applies. The use and (continued) interpretation of specified times to complete the actions of LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times.

A unit shutdown required in accordance with LCO 3.0.3 may be terminated and occurs:

LCO 3.0.3 exited if any of the following

a. The LCO is now met.

b. A Condition exists for which the Required Actions have now been performed.

c. 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 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> for the unit to be in NODE 4 when a shutdown is required during NODE 1 operation. If the unit is in a lower NODE of operation when a shutdown is required, the time limit for reaching the next lower NODE applies. If a lower NODE is reached in less time than allowed, however, the total allowable time to reach MODE 4, or other applicable MODE, is not reduced. For example, if NODE 2 is reached in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, then the time allowed for reaching NODE 3 is the next 11 hours1.273148e-4 days <br />0.00306 hours <br />1.818783e-5 weeks <br />4.1855e-6 months <br />, because the total time for reaching NODE 3 is not reduced from the allowable limit of 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />. Therefore, if remedial measures are completed that would permit a return to MODE 1, a penalty is not incurred by having to reach a lower MODE of operation in less than the total time allowed.

In NODES 1, 2, and 3, LCO 3.0.3 provides actions for Conditions not covered in other Specifications. The requirements of LCO 3.0.3 do not apply in MODES 4 and 5 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 NODE 1, 2, or 3) because the ACTIONS of individual Specifications sufficiently define the remedial measures to be taken.

(continued)

BFN-UNIT 2 B 3.0-4 Amendment

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LCO Applicability B 3.0 LCO 3.0.3 Exceptions to LCO 3.0.3 are provided in instances where (continued) 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 3.7.6, "Spent Fuel Storage Pool Mater Level." LCO 3.7.6 has an Applicability of "During movement of irradiated fuel assemblies in. the spent fuel storage pool." Therefore, this LCO can be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3.7.6 are, not met while in MODE I, 2, or 3, there is no safety benefit to be gained by placing the unit in a shutdown condition. The Required Action of LCO 3.7.6 of "Suspend movement of irradiated fuel assemblies in the spent fuel storage pool" is the appropriate, Required Action to complete in lieu of the actions of LCO 3.0.3. These exceptions are addressed in the individual Specifications.

3.0.4 LCO 3.0.4 establishes limitations on changes in MODES or

't LCO other specified conditions in the Applicability when an LCO is not met. precludes placing the unit in a different MODE or other specified condition stated in that Applicability (e.g., Applicability desired to be entered) when the following exist:

a. Unit conditions are such that requirements of the LCO would not be met in the Applicability desired to be entered; and

b. Continued noncompliance with the LCO requirements, if the Applicability wer e entered, would result in the unit being required to exit the Applicability desired to be entered to comply with the Required Actions.

Compliance with Required Actions that permit continued operation of the unit for an unlimited period of time in a MODE or other specified condition provides an acceptable level of safety for continued operation. This is without regard to the status of the unit before or after the MODE change. Therefore, in such cases, entry into a MODE or other specified condition in the Applicability may be made in accordance with the provisions of the Required Actions.

The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good (continued)

BFN-UNIT 2 'B 3.0-5 Amendment

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LCO Applicability B 3.0 LCO 3.0.4 practice of restoring systems or components to OPERABLE (continued) status before unit startup.

The provisions of L'CO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown.

Exceptions to LCO 3.0.4 are stated in the individual Specifications. Exceptions may apply to all the ACTIONS or to a specific Required Action of a Specification.

LCO 3.0.4 is only applicable when entering MODE 3 from MODE 4, MODE 2 from MODE 3 or 4; or MODE 1 from MODE 2.

Furthermore, LCO 3.0.4 is applicable when entering any other specified condition in the Applicability only while operating in MODE 1, 2, or 3. The requirements of LCO 3.0.4 do not apply in MODES 4 and 5, or in other specified conditions of the Applicability (unless in MODE 1, 2, or 3) because the ACTIONS of individual specifications sufficiently define the remedial measures to be taken. [In some cases (e.g , .) these ACTIONS provide a Note that states "awhile this LCO is not met, entry into a MODE or other specified, condition in the Applicability is not permitted, unless required to comply with ACTIONS." This Note is a requirement explicitly precluding entry into a MODE or other specified condition of the Applicability.]

Surveillances do not have to be performed on the associated inoperable equipment (or on variables outside the specified limits), as permitted by 'SR 3.0. 1. Therefore, changing

'MODES or other specified conditions whil'e in an ACTIONS Condition, either in compliance with LCO 3.0.4 or where an exception to LCO 3.0.4 is stated, is not a violation of SR 3.0.1 or SR 3.0.4 for those Surveillances that do not have to be performed due to the associated 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.

(continued)

BFN-UNIT 2 B 3.0-6 Amendment

0 LCO Applicability B 3.0 BASES. (continued)

LCO 3.0.5 LCO 3.0.5 establishes the 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 this 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 testing to demonstrate:

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

b. The OPERABILITY of other equipment; or

c. That variables are within limits.

The administrative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the allowed testing. This Specification does not provide time to perform any other preventive or corrective maintenance.

An example of demonstrating the OPERABILITY of the equipment being returned to service is reopening a containment isolation valve that has been closed to comply with Required Actions and must be reopened to perform the SRs.

An example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to prevent the trip function from occurring during the performance of an SR on another channel in the other trip system. A similar example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to permit the logic to function and'ndicate the appropriate response during the performance of an SR on another channel in the same trip system.

LCO 3.0.6 LCO 3.0.6 establishes an exception to LCO 3.0.2 when a supported system LCO is not met solely due to a support system LCO not being met. This exception is provided because LCO 3.0.2 would require that the Conditions and (continued)

BFN-UNIT 2. B 3.0-7 Amendment

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LCO Applicability B 3.0 LCO 3.0.6 Required Actions of the associated inoperable supported (continued) system LCO be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the plant is maintained in a safe condition are specified in the support Required Actions. The potential confusion and systems'CO's inconsistency of requirements related to the entry into multiple support and supported systems'CO's Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the plant is maintained in a safe condition in the support system's Required Actions.

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

Specification 5.5. 11, "Safety Function Determination Program (SFDP)," ensures loss of safety function is detected and appropriate actions are taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other limitations, remedial actions, or compensatory actions may be identified as a result of the support system inoperability and corresponding exception to entering supported system Conditions and Required Actions. The SFDP implements the requirements of LCO 3.0.6.

1 The SFDP requires cross division checks to identify a loss of safety function for those support systems that support safety systems are required. The cross division check verifies that the supported systems of the redundant OPERABLE support system are OPERABLE, thereby ensuring safety function is retained. If this evaluation determines that a 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.

(continued)

BFN-UNIT 2 B 3.0-8 Amendment

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LCO Applicability B 3.0 BASES (continued)

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 activities, and to perform special evolutions. Special Operations LCOs in Section 3.10 allow specified TS requirements to be changed to permit performances of these special tests and operations, which otherwise could not be performed 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 NODE or other specified condition not directly associated with or required to be changed to perform the special test or operation will remain in effect.

The Applicability of a Special Operations LCO represents a condition not necessarily in compliance with the normal requirements of the TS. Compliance with Special Operations LCOs is optional. A special operation may be performed either under the provisions of the appropriate Special Operations LCO or under the other applicable TS requirements. it If is desired to perform the special operation under the provisions of the Special Operations LCO, the requirements of the Special Operations LCO shall be followed. Mhen a Special Operations LCO requires another LCO to be met, only the requirements of the LCO statement are required to be met regardless of that LCO's Applicability (i.e., should the requirements of this other LCO not be met, the ACTIONS of the Special Operations LCO apply, not the ACTIONS of the other LCO). However, there are instances where the Special Operations LCO's ACTIONS may direct the other LCO's ACTIONS be met. The Surveillances of the other LCO are not required to be met, unless specified in the Special Operations LCO. If conditions exist such that the Applicability of any other 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.

BFN-UNIT 2 B 3.0-9 Amendment

il'l SR Applicability B 3.0 B 3.0 SURVEILLANCE RE(UIREMENT (SR) APPLICABILITY BASES SRs SR 3.0.1 through SR 3.0.4 establish the general requirements applicable to al.l Specifications and apply at all times, unless otherwise stated.

SR 3.0.1 SR 3.0.1 establishes the requirement that SRs must be met during the NODES 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 j

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 NODE or other specifi'ed 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 requirements of a Specification.

Surveillances, including Surveillances invoked by 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 accordance with SR 3.0.2, prior to returning equipment to OPERABLE status.

(continued)

BFN-UNIT 2 B 3.0-10'mendment

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SR Applicability B 3.0 SR 3.0.1 Upon completion of maintenance, appropriate post maintenance (continued) 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 NODE 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 performing its function. This will allow operation to proceed to a NODE 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

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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 (HPCI) maintenance during shutdown that requires system functional tests at a specified pressure. Provided other appropriate testing is satisfactorily completed, startup can proceed with HPCI considered OPERABLE. This allows operation to reach the specified pressure to complete the necessary post maintenance testing.

SR 3.0.2 SR 3.0.2 establishes the requirements for meeting the specified Frequency for Surveillances and any Required Action with a Completion Time that requires the periodic performance of the Required Action on a "once per..."

interval.

SR 3.0.2 permits a 25K extension- of the interval specified in the Frequency. This extension facilitates Surveillance scheduling and considers plant operating conditions that may not be suitable for conducting the Surveillance (e.g.,

(continued)

BFN-UNIT 2 B 3.0-11 Amendment

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SR Applicability B 3.0 BASES SR 3.0.2 transient conditions or other ongoing Surveillance or (continued) 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 particular 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 exceptions are stated in the individual Specifications. An example of where SR 3.0.2 does not apply is a Surveillance with a Frequency of "in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions." The requirements of regulations take precedence over the TS. The TS cannot in and of themselves extend a test interval. specified in the regulations.

Therefore, there is a Note in the Frequency stating, "SR 3.0.2 is not applicable."

As stated in SR 3.0.2, 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 considered 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 merely as an operational convenience to extend Surveillance intervals (other than those consistent with refueling 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 (continued)

BFN-UNIT 2 B 3.0-12 Amendment

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SR Applicability B 3.0 SR 3.0.3 been completed within the specified Frequency. A delay (continued) period of up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or up to the limit of the specified frequency, whichever is less, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with SR 3.0.2, and not at the time that the specified 'Frequency was not met.

This delay period provides adequate time to complete Surveillances that have been missed. This delay period

-permits the completion of a Surveillance before complying with Required Actions or other remedial measures that might preclude completion of the Surveillance.

The basis for this delay period includes consideration of unit conditions,. adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements.

When a Surveillance with a Frequency based not on time intervals, but upon specified unit conditions or operational situations, is discovered not to have been performed when specified, SR 3.0.3 allows the full delay period of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to perform the Surveillance.

SR 3.0.3 also provides a time limit for completion of Surveillances that become applicable as a consequence of

'NODE changes imposed by Required Actions.

Failure to comply with specified Frequencies for SRs is expected to be an'nfrequent occurrence. Use of the delay period established by SR 3.0.3 is a flexibility which is not intended to be used as an operational convenience to extend Surveillance intervals.

If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and 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 equipment is inoperable, or the variable is 0 (continued)

BFN-UNIT 2 B 3.0-13 Amendment

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SR Applicability B 3.0 BASES SR 3.0.3 outside the specified limits and the Completion Times of the (continued) Required Actions for the applicable LCO Conditions begin immediately upon the failure of the Surveillance.

Completion of the Surveillance within the delay period a1lowed 'by this Specification, or within the Completion Time of the ACTIONS, restores compliance with SR 3.0. 1.

SR 3.0.4 SR 3.0.4 establishes the requirement that all applicable SRs must be met before entry into a MODE or other specified condition in the Applicability.

This Specification ensures that system and component OPERABILITY requirements and variable limits are met .before entry into:MODES or other specified conditions in the Applicability for which these systems and components ensure safe operation of the unit.

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

However, in certain circumstances failing 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(s) are not required to be performed, per SR 3.0. 1, which states that Surveillances do not have to be performed on inoperable equipment. When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance(s) within the specified Frequency d'oes not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the Applicability.

However, since the LCO is not met in this instance, LCO 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes.

The provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability (continued)

BFN-UNIT 2 B 3.0-14 Amendment

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SR Applicability B 3.0 SR 3.0.4 that are required to comply with ACTIONS. In addition, the (continued) provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown.

The precise 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 Surveillance, or both. This allows performance of Surveillances when the prerequisite condition(s) specified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated LCO prior to the performance or completion of a Surveillance. A Surveillance that could not be performed until after entering the LCO Applicability would have its Frequency specified such that it is not "due" until the specific conditions needed are met. Alternately, the Surveillance may be stated in the form of a Note as not required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific 'formats of SRs'nnotation is found in Section 1.4, Frequency.

SR 3.0..4 is only applicable when entering MODE 3 from MODE 4, MODE 2 from MODE 3 or 4, or MODE 1 from NODE 2.

Furthermore, SR 3.0.4 is applicable when entering any other specified condition in the Applicability only while operating in MODE 1, 2, or 3. The requirements of SR 3.0.4 do not apply in NODES 4 and 5, or in other specified conditions of the Applicability (unless in MODE 1, 2, or 3) because the ACTIONS of individual Specifications sufficiently define the remedial measures to be taken.

BFN-UNIT 2 B 3.0-15 Amendment

ik SDM B 3.1.1 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.1 SHUTDOWN MARGIN (SDM)

BASES BACKGROUND SDM requirements are specified to ensure:

a~ The reactor can be made subcritical from all operating conditions and transients and Design Basis Events;

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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 inadvertent criticality in the shutdown condition.

These requirements are satisfied by the control rods, as described in GDC 26 (Ref. 1), which can compensate for the reactivity effects of the fuel and water temperature changes experienced during all operating conditions.

APPLICABLE The control rod drop accident (CRDA) analysis (Refs. 2

.SAFETY ANALYSES and 3) assumes the core is subcritical 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 could exceed the fuel damage limits for a CRDA (see Bases for LCO 3.1.6, "Rod Pattern Control" ). Also, SDM is assumed 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 refueling are covered in Special Operations LCO 3. 10.6, "Multiple Control Rod Withdrawal - Refueling.") The analysis assumes this condition is acceptable since the core will be (continued)

BFN-UNIT 2 B 3.1-1 Amendment

0 SDM B 3.1.1 BASES APPLICABLE shut down with the highest worth control rod withdrawn, has been demonstrated.

if SAFETY ANALYSES adequate SDM (continued)

Prevention or mitigation of reactivity insertion events is necessary to limit energy deposition in the fuel to prevent significant fuel damage, which could result in undue release of radioactivity. Adequate SDM ensures inadvertent criticalities and potential CRDAs involving high worth control rods (namely the first control rod withdrawn) will not cause significant fuel damage.

SDM satisfies Criterion 2 of the NRC Policy Statement (Ref. 8).

LCO The specified SDH limit accounts for the uncertainty in the demonstration of SDM by testing. Separate SDM limits are provided for testing where the highest worth control rod is determined analytically or by measurement. This is due to the reduced uncertainty in the SDH test when the highest worth control rod is determined by measurement. When SDM is demonstrated by calculations not associated with a test (e.g., to confirm SDH during the fuel loading sequence),

additional margin is included to account for uncertainties in the calculation. To ensure adequate SDM during the design process, a design margin is included to account for uncertainties in the design calculations (Ref. 6).

APPLICABILITY In MODES 1 and 2, SDM must be provided because subcriticality with the highest worth control rod withdrawn is assumed in the CRDA analysis (Ref. 2). In MODES 3 and 4, SDM is required to ensure the reactor will be held subcritical with margin for a single withdrawn control rod.

SDM 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 or a fuel assembly insertion error (Ref. 5).

(continued)

BFN-UNIT 2 B 3.1-2 Amendment

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SDM B 3.1.1 BASES (continued)

ACTIONS A.l With SDM not within the limits of the LCO in MODE 1 or 2, SDM must be restored within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Failure to meet the specified SDM may be caused by a control rod that cannot be inserted. The allowed Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is 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.

B.l If the SDM cannot be restored, the plant must be brought to MODE 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, to prevent the potential for further reductions in available SDN (e.g., additional stuck control rods). The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reach NODE 3 from full power conditions in an orderly manner and without challeng'ing plant systems.

0 C.l With SDN not within limits in MODE 3', the operator must immediately initiate action to fully insert all insertable control rods. Action must continue until all insertable control rods are ful.ly inserted. This action results in the least reactive condition for the core.

D. 1 0.2 D.3 and D.4 With SDM not within limits in NODE 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 within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to provide means for control of potential radioactive releases. This includes ensuring secondary containment is OPERABLE; at least two Standby Gas Treatment (SGT) subsystems are OPERABLE; and secondary containment isolation capability (i.e., at least one secondary containment isolation valve (damper) and (continued)

.BFN-UNIT 2 B 3.1-3 Amendment

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SDN B 3.1.1 BASES ACTIONS 0. 1 0.'2 0.3 and 0.4 (continued) associated instrumentation are OPERABLE, or other acceptable administrative controls 'to assure isolation capability) in each associated secondary containment penetration flow path with isolation valve(s) (damper(s)) not isolated that is assumed to be isolated to mitigate radioactive releases.

This may be performed as an administrative check, by examining logs or other information, to determine 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 must continue until all required components are OPERABLE.

E. 1 E.2 E.3 'E.4 and E.5 With SDH not within limits in NODE 5, the operator must immediately suspend CORE ALTERATIONS that could reduce SDM (e.g., insertion of fuel in the core or the withdrawal of control rods). Suspension of these activities 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 must also be immediately initiated to fully inse} t 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 assemblies have been fully inserted. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and therefore do not have to be inserted.

Action must also be initiated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to provide means for control of potential radioactive releases. This includes ensuring secondary containment is OPERABLE; at least two SGT subsystems are OPERABLE; and secondary containment isolation capability (i.e., at least one secondary containment isolation valve (damper) and associated instrumentation are OPERABLE, or other acceptable (continued)

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SDM B 3.1.1 BASES ACTIONS E. 1 E.2 E.3 E.4 and E.5 (continued) administrative controls to assure isolation capability) in each associated secondary containment penetration flow path with isolation valve(s) (damper(s)) not isolated that is assumed to be isolated to mitigate radioactivity releases.

This may be performed as 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 SRs 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.

Action must continue until all required components are OPERABLE.

SURVEILLANCE SR 3.1.1.1 RE(UIREHENTS Adequate SDH must be verified to ensure that the reactor can be made subcritical from any initial operating condition.

This can be accomplished by a test, an evaluation, or a combination of the two. Adequate SDH is demonstrated before or during the first startup after fuel movement, or shuffling within the reactor pressure vessel, 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. Since core reactivity will vary during the cycle as a function of fuel depletion and poison burnup, the beginning of cycle (BOC) test must also account for changes in core reactivity during the cycle. Therefore, to obtain the SDH, the initial measured value must be increased by an adder, "R", which is the difference between the calculated value of maximum core reactivity during the operating cycle and the calculated BOC core reactivity. If the value of R is negative (that is, BOC is the most reactive point in the cycle), no correction to the BOC measured value is required (Ref. 7). For the SDH demonstrations that rely solely on calculation of the highest worth control rod, additional margin (0.10% M/k) must be added to the SDH limit of 0.28% M/k to account for uncertainties in the calculation.

(continued)

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SDM B 3.1.1 BASES SURVEILLANCE SR 3.1.1.1 (continued)

REQUIREMENTS 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 criticals, where the highest worth control rod is determined by testing.

Local critical tests require the withdrawal of out of sequence control rods. This testing would therefore require bypassing of the rod worth minimizer to allow the out of sequence withdrawal, and therefore additional requi} ements must be met (see LCO 3. 10.7, "Control Rod Testing- Operating" ).

The Frequency of 4 hours after, reaching criticality is allowed to provide a reasonable amount of time to perform the required calculations and have appropriate verification.

During MODE 5, adequate SDM is required to ensure 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 core) is required to ensure adequate SDM is maintained during refueling. This evaluation ensures that the intermediate loading patterns are bounded by the safety analyses for the final core 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 bounding analyses include additional margins to the associated uncertainties. Spiral offload/reload sequences inherently satisfy the SR, provided the fuel assemblies are reloaded in the same configuration analyzed for the new cycle. A spiral. reload sequence does not preclude the practice of bridging between SRMs and filling in the center in order to provide for conservative core monitoring during core alterations. Removing fuel from the core will always result in an increase in SDM.

REFERENCES l. 10 CFR 50, Appendix A, GDC 26.

2. FSAR, Section 14.6.2.

(continued)

BFN-UNIT 2 B 3.1-6 Amendment

il SDM B 3.1.1 BASES

3. NEDE-24011-P-A-11-US, "General Electric Standard Appl.ication, for Reactor Fuel," Supplement for United States, Section S.2.2.3. 1, November 1995.

4. FSAR, Section 14.5.3.3.

REFERENCES 5. FSAR, Section 14.5.3.4.

(continued)

6. FSAR, Section 3.6.5.2.

7. NEDE-24011-P,-A-11, "General .Electric Standard Application for Reactor Fuel," Section 3.2.4.1, November 1995.

8. NRC 93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

(continued)

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Reactivity Anomalies B 3.1.2 B 3.1 REACTIVITY CONTROL SYSTEHS B 3.1.2 Reactivity Anomalies BASES BACKGROUND In accordance with GDC 26, GDC 28, and GDC 29 (Ref. 1),

reactivity shall be controllable such that subcriticality is maintained under cold conditions and acceptable fuel design limits are not exceeded during normal operation and abnormal operational transients. Therefore, reactivity anomaly is used as a measure of the predicted versus measured core reactivity during power operation. The continual confirmation of core reactivity is necessary to ensure that the Design Basis Accident (DBA) and transient safety analyses remain valid. 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 reactivity, and could potentially result in a loss of SDH or violation of acceptable 'fuel design limits. Comparing predicted versus measured core reactivity validates the nuclear methods used in the safety analysis and supports the SDH demonstrations (LCO 3.1.1, "SHUTDOWN HARGIN (SDH)") in assuring the reactor can be brought safely to cold, subcritical conditions.

When the reactor core is critical or in normal power operation, a reactivity balance exists and the net reactivity is zero. A comparison of predicted 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 the core design is balanced by the negative reactivity of the control components, thermal feedback, neutron leakage, and materials in the core that absorb neutrons, such as burnable absorbers, producing zero net reactivity.

In order to achieve the required fuel cycle energy output, the uranium enrichment in the new fuel loading and the fuel loaded in the previous cycles provide excess positive reactivity beyond that required to sustain steady state operation at the beginning of cycle (BOC). When the reactor is critical at RTP and operating moderator temperature, the excess positive reactivity is compensated by burnable absorbers (e.g., gadolinia), control rods, and whatever neutron (continued)

BFN-UNIT 2 B 3.1-8 Amendment

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Reactivity Anomalies B 3.1.2 BASES BACKGROUND poisons (mainly xenon and samarium) are present in the fuel.

(continued) The predi'cted core reactivity, as represented by control rod density, is calculated by a 3D core simulator code as a function of cycle exposure. This calculation is performed for projected operating states and conditions throughout the cycle. The core reactivity is determined from control rod densities for actual 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 or implicit assumption in the accident analysis evaluations (Ref. 2). In particular, SDM and reactivity transients, such as control. rod withdrawal accidents or rod drop accidents, are very sensitive to accurate prediction of core reactivity. These accident analysis evaluations rely on computer codes that have been qualified against available test data, operating plant data, and analytical benchmarks.

Monitoring reactivity anomaly provides additional assurance that the nuclear methods provide an accurate representation of the core reactivity.

The comparison between measured and predicted initial cor e reactivity. provides a normalization for the calculational models used to predict core reactivity. If the measured and predicted rod density for identical core conditions at BOC do not reasonably agree, then the assumptions used in the reload cycle design analysis or the calculation models used

~

to predict rod density may not be accurate. If reasonable agreement between measured and predicted core reactivity exists at BOC,'then the prediction may be normalized to the measured value. Thereafter, any significant deviations in the measured rod density from the predicted rod density that develop during fuel depletion may be an indication that the assumptions of the DBA and transient analyses are no longer valid, or that an unexpected change in core conditions has occurred.

Reactivity anomalies satisfy Criterion 2 of the NRC Policy Statement (Ref. 3).

(continued)

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Reactivity Anomalies B 3.1.2 LCO The reactivity anomaly limit is established to ensure plant operation is maintained within the assumptions of the safety analyses. Large differences between monitored and predicted core reactivity may indicate that the assumptions of the DBA

'nd transient analyses are no longer valid, or that the uncertainties in the "Nuclear Design Methodology" are larger than expected. A limit on the difference between the monitored and the predicted rod density corresponding to a reactivity difference of i 1% M/k has been established based on engineering judgment. A > I/o deviation in reactivity from that predicted is larger than expected for normal operation and should therefore be evaluated.

APPLICABILITY In MODE 1, most of the control rods are withdrawn and steady state operation is typically achieved. Under these conditions, the comparison between predicted and monitored core reactivity provides an effective measure of the reactivity anomaly. In MODE 2, control rods are typically being withdrawn during a startup. In MODES 3 and. 4, all control rods are fully inserted and therefore the reactor is in the least reactive state, where monitoring core reactivity is not necessary. In MODE 5, fuel loading results in a continually changing core reactivity. SDM requirements (LCO 3. 1. 1) ensure that fuel movements are performed within the bounds of the safety analysis, and an SDM demonstration is required during the first startup following operations that could have altered core reactivity (e.g., fuel movement, control rod replacement, shuffling).

The SDM test, required by LCO 3.1. 1, provides a direct comparison of the predicted and monitored core reactivity at cold conditions; therefore, the reactivity anomaly LCO is not applicable during these conditions.

ACTIONS A.1 Should an anomaly develop between actual and expected critical rod configuration, 'the core reactivity difference must be restored to within the limit to ensure continued operation is within the core design assumptions.

Restoration to within the limit could be performed by an evaluation of the core design and safety analysis to determine the reason for the anomaly. This (continued)

BEN-UNIT 2 B 3.1-10 Amendment

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Reactivity Anomalies B 3.1.2 BASES ACTIONS A. 1 (continued) evaluation normally reviews the core conditions to determine their consistency with input to design calculations.

Neasured core and process 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 verify that they are adequate for representation of the core conditions. The required Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is based on the low probability of a DBA occurring during this period, and allows sufficient time to assess the physical condition of the reactor and complete the evaluation of the core design and safety analysis.

B.1 If the core reactivity cannot be restored to within the 1% Zdc/k limit, the plant must be brought to a,NODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least NODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reach NODE 3 from full power conditions. in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.1.2.1

.REQUIRENENTS Verifying the reactivity difference between the actual critical rod configuration and the expected configuration is within the 'limits of the LCO provides added assurance that plant operation is maintained within the assumptions of the DBA and transient analyses. The core monitoring software calculates the k-effective for the critical rod configuration and reactor conditions. A comparison of this calculated k-effective at the same cycle exposure is used to calculate the reactivity difference. The comparison is required when the core reactivity has potentially changed by a significant amount. This may occur following refueling a in which new fuel assemblies are loaded, fuel assemblies are shuffled within the core, or control rods are replaced or shuffled. Control rod (continued).

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Reactivity Anomalies B 3.1.2 BASES SURVEILLANCE SR 3.1.2.1 (continued)

RE(U I REM ENTS 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. Also, core reactivity changes during the cycle.

The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> interval after reaching equilibrium conditions following a. startup is based on the need for equilibrium xenon concentrations in the core, such that an accurate comparison between the monitored and predicted rod density 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 flow changes) at a 751'RTP have been obtained. The 1000 NWD/T Frequency was developed, considering the relatively slow change in core reactivity with exposure and operating experience related to variations in core reactivity. This comparison, requires the core to be operating at power levels which minimize the uncertainties and measurement errors, in order to obtain meaningful results. Therefore, the comparison is only done when in NODE 1.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26, GDC 28, and GDC 29.

2. FSAR, Chapter 14.6.

3. NRC 'No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

BFN-UNIT,2 B 3.1-12 Amendment

Cl Control Rod OPERABILITY B 3.1.3 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.3 Control Rod OPERABILITY BASES BACKGROUND 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 limits are not exceeded. In addition, the control rods provide the capability to hold the reactor core subcritical under all conditions 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 of GDC 26, GDC 27, GDC 28, 'and GDC 29 (Ref. 1).

The CRD System consists of 185 locking piston control rod drive mechanisms (CRDMs) and a hydraulic 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 additional energy for scram. An index tube and piston, coupled to the control rod, are locked at fixed increments 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, "Control Rod Scram Times," and LCO 3.1.5, "Control Rod Scram Accumulators,"

ensure that the performance of the control rods in the event of a Design Basis Accident (DBA) or transient meets the assumptions used in the safety analyses of References 2, 3, and 4.

APPLICABLE The analytical methods and assumptions used in the SAFETY ANALYSES evaluations 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 subcritical and for limiting the potential effects of reactivity insertion events caused by malfunctions in the CRD System.

(continued)

BFN-UNIT 2 B 3.1-13 Amendment

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Control Rod OPERABILITY B 3.1.3 APPLICABLE The capability to insert the control rods provides assurance SAFETY ANALYSES that the assumptions for scram reactivity in the DBA and (continued) transient analyses are not violated. Since the SDM ensures the reactor will be subcritical with the highest worth control rod withdrawn (assumed single failure), the additional failure of a second control rod to insert, required, could invalidate the demonstrated SDM and if potentially limit the ability of the CRD System to hold the reactor subcritical. If the control rod is stuck at an inserted position and becomes decoupled from the CRD, a control rod drop accident (CRDA) can possibly occur.

Therefore, the requirement that all control rods be OPERABLE ensures the CRD System can perform its intended function.

The control rods also protect the fuel from damage which could result in release of radioactivity. The limits protected are the MCPR Safety Limit (SL) (see Bases for SL 2.1.1, "Reactor Core SLs" and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), the 1% cladding plastic strain fuel design limit (see Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), and the fuel damage limit (see Bases for LCO 3.1.6, "Rod Pattern Control" )

during reactivity insertion events.

The negative reactivity insertion (scram) provided by the CRD System provides the analytical basis for determination of plant thermal limits and provides protection against fuel damage limits during a CRDA. The Bases for LCO 3.1.4, LCO 3. 1.5, and LCO 3.1.6 .discuss in more detail how the SLs are protected by the CRD System.

Control rod OPERABILITY satisfies Criterion 3 of the NRC Policy Statement (Ref. 6).

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 control rod'osition. Accumulator OPERABILITY is addressed by LCO 3. 1.5. The associated scram accumulator status for a control rod only affects the scram insertion times; therefore, an inoperable accumulator does not immediately require declaring a control rod inoperable.

Although not all control rods are required to be OPERABLE to (continued)

BFN-UNIT 2 B 3.1-14 Amendment

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Control Rod OPERABILITY B 3.1.3 BASES LCO satisfy the intended reactivity control requirements, strict (continued), control over the number and, distribution of inoperable control rods is required to satisfy the assumptions of the DBA and transient analyses.

APPLICABILITY In MODES I and 2, the, control rods are assumed to function during a DBA or transient and are therefore required to be OPERABLE in these HODES. 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."

ACTIONS The ACTIONS Table is. modified by a Note indicating that a separate Condition entry is allowed for each. control rod.

This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable control rod. Complying with the Required .Actions may allow for continued operation, and subsequent inoperable control rods are governed by subsequent Condition entry and application of associated Required Actions.

A.l A.2 A.3 and A.4 A control rod is considered stuck if it will not insert by either CRD drive water or scram pressure. With a fully inserted control rod stuck, no actions are requi'red as long as the control rod remains fully inserted. The Required Actions are modified by a Note, which allows the rod worth minimizer (RWH) to be bypassed if required to allow continued operation. LCO 3.3.2.1, "Control Rod Block Instrumentation," provides additional requirements when the RWH is bypassed to ensure compliance with the CRDA analysis.

Wi,th one withdrawn control rod stuck, the local scram reactivity rate assumptions may not be met if the stuck control rod separation criteria are not met. Therefore, a verification that the separation criteria are met must be performed immediately. The separation criteria are not met if a)'he stuck control rod occupies a location adjacent to

.(continued)

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Control Rod OPERABILITY 8 3.1.3 BASES ACTIONS A. 1 A.2 A.3 and A.4 (continued) 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 a1so adjacent to another "slow" control rod, or c) the stuck control rod, occupies a location adjacent to one "slow" control rod when there is another pair of "slow" control rods adjacent to one another. The description of "slow" control rod is provided in LCO 3. 1.4, "Control Rod Scram Times." In addition, the associated control rod drive must be disa'rmed in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

Hydraulically disarming does not normally include isolation of the cooling water. The allowed Completion Time of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> is acceptable, considering the reactor can still be shut down, assuming 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 isolated from both scram and normal insert and withdraw pressure. Isolating the control rod from scram prevents damage to the CROM.

Monitoring of'he insertion capability .of each withdrawn control'od must also be performed within 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> s 'from discovery of Condition A concurrent with THERMAL POWER greater than the low power setpoint (LPSP) of,the RWM.

SR 3. 1.3.2 and SR 3. 1.3.3 perform periodic tests of the control rod insertion capability of withdrawn control rods.

Testing. each withdrawn control rod ensures that a generic problem does not exist. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." The Required, Action A.3 Completion Time only begins upon discovery that THERMAL POWER is 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 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from discovery of Condition A concurrent with THERMAL POWER greater than the LPSP of the RWM provides a reasonable time to test the control rods, considering the potential for a need to reduce power to perform the tests.

To allow, continued operation with a withdrawn control rod stuck, an evaluation of adequate SDM is also required within 72 hours. Should a DBA or transient require a shutdown, to (continued)

BFN-UNIT 2 8 3.1-16 Amendment

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Control Rod OPERABILITY B 3.1.3 BASES ACTIONS A. 1 A.2 A.3 and A.4 (continued) preserve the single failure criterion, an additional control rod would have to be assumed to fail to insert when required. Therefore, the original SDM demonstration may not be valid. The SDM must therefore be evaluated (by measurement or analysis) with the stuck control rod at its stuck position and the highest worth OPERABLE control rod assumed to be fully withdrawn.

The allowed Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to verify SDM is adequate, considering that with a single control rod stuck in a withdrawn position, the remaining OPERABLE control rods are capable of providing the required scram and shutdown reactivity. Failure to reach MODE 4 is only likely an if additional control rod adjacent to the stuck control rod also fails to insert during a required scram.

B 1 and B2 With two or more withdrawn control rods stuck, the stuck control rods must be isolated from scram pressure within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and the plant brought to MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

The control rod must be isolated from both scram and normal insert and withdraw pressure. Isolating the control rod from scram prevents damage to the CRDM. The allowed Completion Time is acceptable, considering the low probability of a CRDA occurring during this interval. The occurrence of more than one control rod stuck at a withdrawn position increases the probability that the reactor cannot be shut down if required. Insertion of all insertable control rods eliminates the possibility of an additional failure of a control rod to insert. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

C.l and C.2 With one or more control rods inoperable for reasons other than being stuck in the withdrawn position, operation may continue, provided the control rods are fully inserted (continued)

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Control Rod OPERABILITY B 3.1.3 BASES ACTIONS C. 1 and C.2 (continued) within 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 (electrically or hydraulically) to prevent inadvertent withdrawal during subsequent operations. The control rods can be hydraulically disarmed by closing the drive water and exhaust water isolation valves while maintaining cooling water to the CRD. The control rods can be electrically disarmed by disconnecting power from all four directional control valve solenoids.

Required Action C.l is modified by a Note, which allows the RWM to be bypassed if required to allow insertion of the inoperable control rods and continued operation.

LCO 3.3.2.1 provides additional requirements when the RWN 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 an orderly manner and without challenging plant systems.

D.l and D.2 Out of sequence control rods may increase the potential reactivity worth of a dropped control rod during a CRDA. At

~ 10% RTP, the generic banked position withdrawal sequence (BPWS) analysis (Ref. 5) requires inoperable control rods not in compliance with BPWS 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 in compliance with BPWS and not separated by at least two OPERABLE control rods, action must be taken to restore compliance with BPWS or restore the control rods to OPERABLE status. Condition D is modified by a Note indicating that the Condition is not applicable when

) 10% RTP, since the BPWS is not required to be followed under these conditions, as described in the Bases for LCO 3. 1.6. The allowed Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is acceptable, considering the low probability of a CRDA occurring.

(continued)

BFN-UNIT 2 B 3.1-18 Amendment

il Control Rod OPERABILITY B 3.1.3 ACTIONS E.l (continued)

If any Required Action and associated Completion Time of Condition A, C, or D are not met, or there are nine or more inoperable control rods, the plant must be brought to a NODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This

'ensures all insertable control rods are inserted and places the reactor in a condition that does not require the active function (i.e., scram) of the control rods. Below 10% RTP, the generic banked position -withdrawal sequence (BPWS) analysis (Ref. 5) allows a maximum of eight bypassed control rods. The number of control, rods permitted to be inoperable when operating above 10% RTP (e.g., no CRDA considerations) could be more than the value specified, but the occurrence of a large number of inoperable control rods could be indicative of a generic problem, and investigation and resolution of the potential problem should be undertaken.

The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency of this SR is based on operating experience related to expected changes in control rod position and the availability of control rod position indications in the control room.

SR 3.1.3.2 and 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 (continued)

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Control Rod OPERABILITY B 3.1.3 BASES SURVEILLANCE SR 3. 1.3.2 and SR 3. 1.3.3 (continued)

REQUIREMENTS position. This ensures the control rod is not stuck and is free to insert on a scram signal. These Surveillances are not required when THERMAL POWER is less than or equal to the

.actual LPSP of the RWM, since the notch insertions may not be compatible with the requirements of banked position withdrawal sequence (BPWS) (LCO 3. 1.6) and the RWM (LCO 3.3.2. 1). The 7 day Frequency of SR 3.1.3.2 is based on operating experience related to the changes in CRD performance and the ease of performing notch testing for fully withdrawn control rods. Partially withdrawn control rods are tested at a 31 day Frequency, based on the potential power reduction required to allow the control rod movement and considering the large testing sample of SR 3.1.3.2. Furthermore, the 31 day Frequency takes into account operating experience related to changes in CRD performance. At any time, if a control rod is immovable, a determination of that control rod's trippability must be made and appropriate action taken.

SR 3.1.3.4 Verifying that the scram time for each control rod to notch position 06 is c 7 seconds provides reasonable assurance that the control rod will insert when required during a DBA 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, "Reactor 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 associated Frequencies are acceptable, considering the more frequent testing performed to demonstrate other aspects of control rod OPERABILITY and operating experience, which.

shows scram times do not significantly change over an operating cycle.

(continued)

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Control Rod OPERABILITY B'.1.3 SURVEILLANCE SR 3.1.3.5 RE(UIREHENTS (continued) Coupling verification is performed to ensure the control rod is connected to the CRDM 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 .the "full out" position (notch position 48) or prior to declaring the control rod OPERABLE after work on the control rod or CRD System that could affect coupling. This includes control rods inserted one notch and then returned to the "full out" position 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 being moved and operating experience related to uncoupling events.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26, GDC 27, GDC 28, and GDC 29.

2. FSAR, Section 3.4.6.

3. FSAR, Section 14.5.

4. FSAR, Section 14.6.

5. NED0-21231, "Banked Positi,on Withdrawal Sequence,"

Section 7.2, January. 1977.

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

BFN-UNIT 2 B 3.1.-21 Amendment

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Control Rod Scram Times B 3.1.4 B 3.1.4 Control Rod Scram Times BASES BACKGROUND The scram function of the Control Rod Drive (CRD) System controls reactivity changes during abnormal operational transients to ensure that specified acceptable fuel design limits are not exceeded (Ref. 1). The control rods are

,scrammed by positive means using hydraulic pressure exerted on the CRD piston.

When a scram signal is initiated, control air is vented from the scram valves, all'owing them to open by spring action.

Opening the exhaust valve reduces the pressure above the main drive piston to atmospheric pressure, and opening the inlet 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 differential 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 scram action. If the reactor pressure is low, such as during startup, the accumulator will fully insert the control rod in the required time without assistance from reactor pressure.

APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the control rod scram function are presented. in References 2, 3, and 4. The Design Basis Accident (DBA) 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 determination of plant thermal limits {e.g., the NCPR). Other distributions of scram times (e.g., several control rods scramming slower than the average time with several control rods scramming faster than the average time) can also provide sufficient scram reactivity. Surveillance of each individual control rod's scram time ensures the scram reactivity assumed in the

,DBA and transient analyses can be met.

{continued)

BFN-UNIT 2 B 3.1-22 Amendment

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Control Rod Scram Times

~ B 3.1.4 APPLICABLE The scram function of the CRD System protects the MCPR SAFETY ANALYSES Safety Limit (SL) (see Bases for SL 2. 1. 1, "Reactor Core (continued) SLs," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)")

and the 1% cladding plastic strain fuel design limit (see Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), which ensure that no fuel damage will 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 analyzed 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 LCO 3. 1.6, "Rod Pattern Control" ). For the reactor vessel overpressure protection analysis, the scram function, along with the safety/relief valves, ensure that the peak vessel pressure is maintained within the applicable ASME Code limits.

Control rod scram times satisfy Criterion 3 of the NRC Policy Statement (Ref. 7).

LCO The scram times specified in Table 3.1.4-1 (in the accompanying LCO) are required to ensure that the scram reactivity assumed in the DBA and transient analysis is met (Ref. 6).

To account for single failures and "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 exceeding the specified limits (i.e., "slow" control rods) assuming a single stuck control rod (as allowed 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 as a function of reactor steam dome pressure to account for the pressure dependence of the scram times. The scram times are specified relative to measurements based on reed switch positions, which provide the control rod position indication. The reed switch closes ("pickup") when the index tube passes a specific location and then opens (continued)

BFN-UNIT 2 B 3.1-23 Amendment

il Control Rod Scram Times B 3.1.4 BASES LCO ,("dropout") as the index tube travels upward. Verification (continued) of the specified scram times in Table 3. 1.4-1, is accomplished through measurement of the "dropout" times. To ensure that local scram reactivity rates are maintained within acceptable limits, no more than two of the allowed "slow" control rods may occupy adjacent locations.

Table 3.1.4-1 is modified 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 (LCO 3.1.3)'. Slow scramming control rods can be conservatively declared inoperable and not accounted for as "slow" control rods.

APPLICABILITY In NODES 1 and 2, a scram is assumed to function during transients and accidents analyzed for these plant conditions. These events are assumed to occur during startup and power operation; therefore, the scram function of the control rods is required during these NODES. In NODES 3 and 4, the control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod bl.ock is applied. This provides adequate requirements for control rod scram capability during these conditions.

Scram requirements in NODE 5 are contained in LCO 3.9.5, "Control 'Rod OPERABILITY-Refueling."

ACTIONS A. 1 When the requirements of this LCO are not met, the rate of negative reactivity insertion during a scram may not be within the assumptions of the safety analysis. Therefore, 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 NODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based. on operating experience, to reach NODE 3 from full'ower conditions in an orderly manner and without challenging plant systems.

(continued)

BFN-UNIT 2 B 3.1-24 Amendment

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Control Rod Scram Times 8 3.1.4 SURVEILLANCE The four SRs of this LCO are modified by a Note stating that REQUIREMENTS during a single control rod scram time surveillance, the 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 the 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 DBA and transient analyses is based on an assumed control rod scram time. Measurement of the scram times with reactor steam dome pressure a 800 psig demonstrates acceptable 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. Therefore, demonstration of adequate scram times at reactor steam dome pressure w 800 psig ensures that the measured scram times will be, within the speci. fied limits at higher pressures. To ensure that scram time testing is performed within a reasonable time following fuel movement within the reactor pressure vessel after a shutdown ~ 120 days or longer, control rods are required to be tested before exceeding 40% RTP following the shutdown.

The SR is modified by a Note stating that in the event fuel movement is limited to selected core cells, only those CRDs associated with the core cells affected by the fuel movements are required to 'be scram time tested. However, if the reactor remains shutdown a 120 days, all control rods are required to be scram time tested. This Frequency is 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 work on control rods or the CRD System.

(continued)

BFN-UNIT 2 B 3.1-25 Amendment

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Control Rod Scram Times' 3.1.4 BASES SURVEILLANCE SR 3.1.4.2 REQUIREMENTS 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 least 10% of the control rods. This sample remains representative if no more than 20% of the control rods in the sample tested are determined to be "slow." With more than 20% of the sample declared to be "slow" per the criteria in Table 3. 1.4-1, additional control rods are tested until this 20% criterion (i.e., 20% of the entire sample) is satisfied, or until the total number of "slow" control rods (throughout the core from al'l Surveillances) exceeds the LCO limit. For planned testing, the control rods selected for the sample should be different for each test. Data from inadvertent scrams should be used whenever possible to avoid unnecessary testing at power, even if the control rods with data may have been previously tested in a sample. The 120 day Frequency is based on operating experience that has shown control rod scram times do not significantly change over an operating cycle. This Frequency is also reasonable based on the additional Surveillances done on the CRDs at more frequent intervals in- accordance with LCO 3. 1.3 and LCO 3. 1.5, "Control Rod Scram .Accumulators."

SR 3.1.4.3 When work that could affect the scram insertion time is performed on a control rod or the CRD System, testing must be done to demonstrate that each affected control rod retains adequate scram performance over the range of applicable reactor pressures from zero to the maximum permissible pressure. The scram testing must be performed once before declaring the control rod OPERABLE. The required scram testing must demonstrate that for the affected control rod the scram valves open and the scram discharge path is open. This test can be performed with the control rod inserted and the accumulator drained and isolated to minimize potential damage to the drive. The test is adequate based on a high probability of meeting the scram. time testing acceptance criteria at reactor pressures

)

e 800 psig. Limits for 800 psig are found in Table 3.1.4-1.

(continued)

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Control Rod Scram Times B 3.1.4 BASES SURVEILLANCE 'SR 3.1.4.3 (continued)

RE(UI RE>IENTS Specific examples of work that could affect the scram times are (but are 'not limited to) the following: removal of any CRD for maintenance or modification; replacement of a control rod; and maintenance or modification of a scram solenoid pilot valve, scram valve, accumulator, isolation valve or check valve in the piping required for scram.

The Frequency of once prior to declaring the affected control rod OPERABLE 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.

SR 3.1.4.4 When work that could affect the scram insertion time is performed on a control rod or CRD System, testing must be done to demonstrate each affected control rod is still within the 1'imits of Table 3.1.4-1 with the reactor steam dome pressure a 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 pressure and high pressure test may be required. This testing ensures. that, prior to withdrawing the control rod for continued operation, the control rod scram performance is acceptable for operating reactor pressure conditions.

Alternatively, a control rod scram test during hydrostatic pressure testing could also satisfy both criteria.

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 l. 10 CFR 50, Appendix A, GDC 10.

2. FSAR, Section 3.4.6.

3. FSAR, Section 14.5.

(continued)

BFN-UNIT 2 B 3.1-27 Amendment

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Control Rod Scram Times B 3.1'.4 BASES REFERENCES 4. FSAR, Section 14.6.,

(continued)

5. NEDE-'24011-P-A-11, "General Electric Standard Application for 'Reactor Fuel," Section 3.2.4. 1, November 1995.

6.. Letter from R. F. Janecek (BWROG) to R. W. Starostecki (NRC), "BWR Owners Group Revised Reactivity Control System, Technical Specifications," .BWROG-'8754, September 17, 1987.

7.. NRC No..93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

BFN-UNIT 2 B 3.1-28 ,Amendment

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Control Rod Scram Accumulators B 3.1.5 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.5 Control Rod Scram Accumulators BASES BACKGROUND The control rod 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 separates the water 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 SAFETY ANALYSES the control rod scram function are presented in References 1, 2, and 3. The Design Basis Accident (DBA) and transient analyses assume that all of the control rods scram at a specified insertion rate. OPERABILITY of each individual'ontrol rod scram accumulator, along with LCO 3.1.3, "Control Rod OPERABILITY," and LCO 3. 1.4, ensures that the scram reactivity assumed in the DBA and transient analyses can be met. The existence of an inoperable accumulator may,invalidate prior scram time measurements for the associated control rod.

The scram function of the CRD System, and therefore the OPERABILITY of the accumulators, protects the HCPR Safety Limit (see Bases for SL 2.1. 1, "Reactor Core SLs" and LCO 3.2.2, "MINIMUM CRITICAL POMER RATIO (HCPR)") and 1% cladding plastic strain fuel design limit (see Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), which ensure that no fuel damage will occur if these limits are not exceeded (see Bases for LCO 3. 1.4). In addition, 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 LCO 3. 1.6, "Rod Pattern Control" ).

(continued)

BFN-UNIT 2 8 3.1-29 Amendment

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Control Rod Scram Accumulators B 3.1.5 BASES APPLICABLE Control rod scram accumulators satisfy Criterion 3 of the SAFETY ANALYSES NRC Policy Statement (Ref. 4).

(continued)

LCO The OPERABILITY of the control rod scram accumulators is required to ensure that adequate scram insertion capability exists when needed over the entire range of reactor pressures. The OPERABILITY of the scram accumulators 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 accumulators must be OPERABLE to support the scram function.

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. Requirements for scram accumulators in MODE 5 are contained " in LCO 3.9.5, "Control Rod OPERAB I LITYRe fuel i ng.

ACTIONS The ACTIONS Table is modified by a Note indicating that a separate Condition entry is allowed for each control rod scram accumulator. This is acceptable since the Required Actions for each Condition provide appropriate compensatory actions for each affected accumulator. Complying with the Required Actions may allow for continued operation and subsequent affected accumulators governed by subsequent Condition entry and application of associated Required Actions.

A.l and A.2 With one control rod scram accumulator inoperable and the reactor steam dome pressure a 900 psig, the control rod may be declared "slow," since the control rod will still scram at the reactor operating pressure but may not satisfy the required scram times in Table 3.1.4-1.

(continued)

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Control Rod Scram Accumulators B 3.1.5 BASES ACTIONS A. I and A.2 (continued)

Required Action A.l is modi.fied by a Note indicating that declaring the control rod "slow" only applies if the associated control rod 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 "slow" and the further degradation of scram performance with an inoperable accumul.ator could result in excessive scram times. In this event, the associated control rod is declared inoperable (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 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 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 scram only with reactor pressure at high reactor pressures.

B.l B.2.1 and B.2.2 With two or more control rod scram accumulators inoperable and reactor steam dome pressure a 900 psig, adequate pressure must 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 performance.

Therefore, within. 20 minutes from discovery of charging water header pressure ( .940 psig concurrent with Condition B, adequate charging water header pressure must be restored. The allowed Completion 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 declared "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 indicating that declaring the control rod "slow" 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 (continued)

BFN-UNIT 2 B 3.1-31 Amendment

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Control Rod Scram Accumulators B 3.1.5 BASES ACTIONS B. 1 B.2. 1 and B.2.2 (continued)

- would already be considered "slow" and the further degradation of scram performance with an inoperable accumulator 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 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 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 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 inoperable and the reactor steam dome pressure < 900 psig, the pressure supplied to the charging water header must be adequate to ensure that accumulators remain charged. With the reactor steam dome pressure < 900 psig, the function of the accumulators in providing the scram force becomes much more important since the scram function could become severely degraded during a depressurization event or at low reactor pressur es. Therefore, immediately upon discovery of charging water header pressure < 940 psig, concurrent with Condition C, all control rods associated with inoperable accumulators must be verified tobe fully inserted.

Withdrawn control rods with inoperable accumulators may fail to scram under these low pressure conditions. The associated control rods must also be declared inoperable within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The allowed Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is reasonable for Required Action C.2, considering the low probability of a DBA or transient occurring during the time that the accumulator is inoperable.

D.l The reactor mode switch must be immediately placed in the shutdown position if either with Required Action and the loss of the associated CRD charging Completion Time associated pump (Required Actions B.-l and C.l) cannot be met. This (continued)

BFN-UNIT 2 B 3.1-32 Amendment

0 Control Rod Scram Accumulators B 3.1.5 ACTIONS, D.l (continued) ensures that all insertable control rods are inserted and that the reactor is in a condition that does not require the active function (i.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 accumulators are fully inserted, since the function of the control rods has been performed.

SURVEILLANCE SR 3.1.'5.1 REQUIREMENTS SR 3.1.5. 1 requires that the accumulator pressure be checked every 7 days to ensure adequate accumulator pressure exists to provide sufficient scram force. An automatic accumulator monitor may be used to continuously satisfy this requirement. The primary indicator of 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 inoperable. The minimum accumulator pressure of 940 psig is well below the expected pressure of 1100 psig (Ref. 1).

Declaring the accumulator inoperable when the minimum pressure is not maintained ensures that significant degradation in scram times does not occur. The 7 day Frequency has been shown to be acceptable through operating experience and takes into account indications available in the control room.

REFERENCES 1. FSAR, Section 3.4.6.

2. FSAR, Section 14.5.

3. FSAR,, Section 14.6.

4. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

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Rod Pattern Control B 3.1.6 B '3.1 REACTIVITY CONTROL SYSTEHS B 3.1.6 ,Rod Pattern Control BASES BACKGROUND Control rod patterns during startup conditions are controlled by the 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 allowed over the operating range of all control rods inserted to 10% RTP. The sequences limit the potential amount o'f:reactivity addition that could occur in the event of a Control Rod Drop Accident (CRDA).

This Specification assures that 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 1 SAFETY ANALYSES the CRDA are summarized in References withdrawal sequences.

1 and 2. CRDA analyses assume that the reactor operator follows prescribed These sequences define the potential initial conditions for the CRDA analysis. The RWH (LCO 3.3.2.1) provides backup to operator control of the withdrawal sequences to ensure that the initial conditions of the CRDA analysis are not violated.

Prevention or mitigation of positive reactivity insertion events is necessary to limit the energy deposition in the fuel, thereby preventing significant fuel damage which could result in the undue release of radioactivity. Since the failure consequences for UO~ have been shown to be insignificant below fuel energy depositions of 300 cal/gm (Ref. 3), the fuel damage limit of 280 cal/gm provides a-margin of safety from significant core damage which would result in release of radioactivity (Refs. 4 and 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 ASHE Code limits (Ref. 7) and the calculated offsite doses will be wel.l within the required limits (Ref. 5).

(continued)

'BFN-UNIT 2 'B 3.1-34 Amendment

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Rod Pattern Control B 3.1.6 BASES APPLICABLE Control rod patterns analyzed in Reference 1 follow the SAFETY ANALYSES banked position withdrawal sequence (BPWS). The BPWS is (continued) applicable from the condition of all control rods fully inserted to 10% RTP (Ref. 2). For the BPWS, the control rods are .required to be moved in. groups, with all control rods assigned to a specific group required to be within specified banked positions (e.g., between notches 08 and 12). The banked positions are established to minimize the maximum incremental control rod worth without being overly restrictive during normal plant operation. Generic analysis of the BPWS (Ref. 8) has demonstrated that the 280 cal/gm fuel damage limit will not be violated during a CRDA while following the BPWS mode of operation. The evaluation provided by the generi'c BPWS analysis (Ref. 8) allows a limited number (i.e., eight) and corresponding

-

distribution of fully inserted, inoperable control rods, that are not in compliance with the sequence.

Rod pattern control satisfies Criterion 3 of the NRC Policy Statement (Ref. 9).

Compliance with the prescribed control rod sequences minimizes the potential consequences of a CRDA by limiting the initial conditions to those consistent with the BPWS.

This LCO only applies to OPERABLE control rods. For inoperable control rods 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 BPWS.

'APPLICABILITY In MODES 1 and 2, when THERMAL POWER is x 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 no credible control rod configuration that results in a control rod worth that could 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 cell containing fuel assemblies, adequate SDM ensures that the consequences of a CRDA are acceptable, since the reactor will remain subcritical with a single control rod withdrawn.

(continued)

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Rod Pattern Control B 3.1.6 BASES (continued)

ACTIONS A.l and A.2 With one or more OPERABLE control rods not in compliance with the prescribed control rod sequence (Ref. 8), actions may be taken to either correct the control rod pattern or declare the associated control rods inoperable within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. 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 a -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 scram if warranted.

Required Action A.l is modified by a Note which allows the RWH 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 movement by a second licensed operator or a qualified member of the technical staff. 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 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 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 out of sequence, the control rod pattern significantly deviates from the prescribed sequence (Ref. 8). Control rod withdrawal should be suspended immediately 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 (continued)

BFN-UNIT 2 B 3.1-36 Amendment

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Rod Pattern Control B 3.1.6 ACTIONS B. 1 and B.2 (continued) control rods has less impact on control rod worth than withdrawals have. Required Action B. 1 is modified by a Note which al.lows 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 movement by a second licensed operator or a qualified member of the technical staff.

When nine or more OPERABLE control rods are not in compliance with BPWS, the reactor mode switch must be placed in the shutdown position within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. With the mode switch in shutdown, the reactor is shut down, and as such, does not meet the applicability requirements of this LCO.

The allowed Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is reasonable to allow insertion of control rods to restore compliance, and is appropriate relative to the low probability of a CRDA occurring with the control rods out of sequence.

SURVEILLANCE SR 3.1.6.1 REgUIRENENTS The control rod pattern is verified to be in compliance with the BPWS at a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency to ensure the assumptions of the CRDA analyses are met. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency was developed considering that the primary check on compliance with the BPWS is performed by the RWH (LCO 3.3.2.1), which provides control rod blocks to enforce the required sequence and is required to be OPERABLE when operating at a 10% RTP.

REFERENCES 1. NEDE-24011-P-A-11-US, "General Electric Standard Application for Reactor Fuel, Supplement for United States," Section 2.2.3.1, November 1995.

2. Letter from T. Pickens (BWROG) to G. C. Lainas (NRC),

Amendment 17 to General Electric Licensing Topical Report, NEDE-24011-P-A, August 15, 1986.

3. NUREG-0979, Section 4.2. 1.3.2, April 1983.

4. NUREG-0800, Section 15.4.9, Revision 2, July 1981.

(continued)

BFN-UNIT 2 B 3.1-37 Amendment

il Rod 'Pattern Control B 3.1.6 BASES REFERENCES 10 CFR 100.11.

(continued)'.

6. NED0-21778-A, "Transient Pressure Rises Affected Fracture Toughness Requirements for Boiling Mater Reactors," December 1978.

7. .ASNE, Boiler and Pressure Vessel Code.

8. NED0-21231, "Banked Position Withdrawal Sequence,"

January 1977.

9. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

BFN-UNIT 2 B 3.1-38 Amendment

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SLC System B 3.1.7 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.7 Standby Liquid Control (SLC) System BASES BACKGROUND The SLC System is designed to provide the capability of bringing the reactor, at any time in a fuel cycle, from full power and minimum control rod inventory (which is at the peak of the xenon transient) to a subcritical condition with the reactor in the most reactive, xenon free state without taking credit for control rod movement. The SLC System satisfies the requirements of 10 CFR 50.62 (Ref. 1) on anticipated transient without scram.

The SLC System consists of a boron solution storage tank, two positive displacement pumps in parallel and two explosive valves in parallel for redundancy, and associated piping and valves used to transfer borated water from the storage tank to the reactor pressure vessel (RPV). The borated solution is discharged near the bottom of the core shroud, where it then mixes with the cooling water rising through the 'core. A smaller tank containing demineralized water is provided for testing purposes.

The worst case sodium pentaborate solution concentration required to shutdown the reactor with sufficient margin to account for 0.05 Zb/k and Xenon poisoning effects is 9.2 weight percent. This corresponds to a 40'F saturation temperature. The worst case SLCS equipment area temperature is not predicted to fall below 50'F. This provides a 10'F thermal margin to unwanted precipitation of the sodium pentaborate. Tank heating components provide backup assurance that the sodium pentaborate solution temperature will never fall below 50'F but are not required for TS operability considerations.

APPLICABLE The SLC System is manually initiated from the main control SAFETY ANALYSES room, as directed by the emergency operating instructions, if the operator believes the reactor cannot be shut down, or kept shut down, with the control rods. The SLC System is used in the event that enough control rods cannot be (continued)

BFN-UNIT 2 B 3.1-39 Amendment

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SLC System B 3.1.7 BASES APPLICABLE inserted to accomplish shutdown and cooldown in the normal SAFETY ANALYSES manner. The SLC System injects borated water into (continued) the reactor core to add negative reactivity to compensate for all of the various reactivity effects that could occur during plant operations. To meet this objective, it is necessary to inject a quantity of boron, which produces a concentration of 660 ppm of natural boron, in the reactor coolant at 70'F. To allow for imperfect mixing, leakage and the volume in other piping connected to the reactor system, an amount of boron equal to 25% of the amount cited above is added (Ref. 2). This volume versus concentration limit and the temperature versus concentration limits in Figure 3.1.7-1 are calculated such that the required concentration is achieved accounting for dilution in the RPV with normal water level and including the water. volume in the entire residual heat removal shutdown cooling piping and in the recirculation 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 is taken for the portion of the tank volume that cannot be injected.

The SLC System satisfies Criterion 4 of the NRC Policy Statement (Ref. 3).

LCO The OPERABILITY of the SLC System provides 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 SLC subsystems are required to be OPERABLE; each contains an OPERABLE pump, an explosive valve, and associated piping, valves, and instruments and controls to ensure an OPERABLE flow path.

APPLICABILITY In MODES 1 and 2, shutdown capability is required. 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 the reactor remains subcritical. In MODE 5, (continued)

BFN-UNIT 2 B 3.1-40 Amendment

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SLC System B 3.1.7 APPLICABILITY only a single control rod can be withdrawn from a core cell (continued) containing fuel assemblies. Demonstration of adequate SDM (LCO 3.1.1, "SHUTDOWN MARGIN (SDM)") ensures that the reactor will not become critical. Therefore, the SLC System is not required to be OPERABLE when on'ly a single control rod can be withdrawn.

ACTIONS A.1 If one SLC subsystem is inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this condition, the remaining OPERABLE subsystem is adequate to perform the shutdown function. However, the overall reliability is reduced because a single failure in .the remaining OPERABLE subsystem could result in reduced SLC System shutdown capability. The 7 day Completion Time is based on the availability of an OPERABLE subsystem capable of performing the intended SLC System function and the low probability of a Design Basis Accident (DBA) or severe transient occurring concurrent with the failure of the Control Rod Drive (CRD) System to shut down the plant.

B.l If both SLC subsystems are inoperable, at least one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The allowed Completion Time of 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is considered acceptable given the. low probability of a DBA or transient occurring concurrent with the failure of the control rods to shut down the reactor.

C.1 If any Required Action and associated Completion Time is not met, 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 MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

(continued)

BFN-UNIT 2 B 3.1-41 Amendment

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SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.1 RE(UIREHENTS SR 3.1.7.1 is a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Surveillance verifying the volume of the borated solution in the storage tank, thereby ensuring SLC System OPERABILITY without disturbing normal plant operation. This Surveillance ensures that the proper borated solution volume is maintained. The sodium pentaborate solution concentration requirements (c 9.2% by weight) and the required quantity of Boron-10 (a 186 lbs) establish the tank volume requirement. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on operating experience that has shown there are relatively slow variations in the solution volume.

SR 3.1.7.2 SR 3. 1.7.2 verifies the continuity of the explosive charges in the injection valves to ensure that proper operation will occur if required. An automatic continuity monitor may be used to continuously satisfy this requirement. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. The 31 day Frequency is based on operating experience and has demonstrated the reliability of the explosive charge continuity.

SR 3'.1.7.3 and SR 3.1.7.5 SR 3. 1.-7.3 requires an examination of the sodium pentaborate solution by using chemical analysis to ensure that the proper concentration of boron exists in the storage tank.

The concentration is dependent upon the volume of water and quantity of boron in the storage tank. SR 3. 1.7.5 requires verification that the SLC system conditions satisfy the following equation:

C ) Q E > =1.0

( 'f3 WT% )( 86 GPM )( 19.8 ATOM  % )

C = sodium pentaborate solution weight percent concentration g = SLC system pump flow rate in gpm

'E = Boron-10 atom percent enrichment in the sodium pentaborate solution (continued)

BFN-UNIT 2 B 3.1-42 Amendment

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SLC System B 3.1.7 SURVEILLANCE SR 3. 1.7.3 and SR 3. 1.7.5 (continued)

REQUIREMENTS To meet 10 CFR,50.62, the SLC System must have a minimum flow capacity and boron content equivalent in control capacity to 86 gpm of 13 weight percent natural sodium pentaborate solution. The atom percentage of natural B-10 is 19.8%. This equivalency requirement is met when the equation given above is satisfied. The equation can be satisfied by adjusting the solution concentration, pump flow rate or Boron-10 enrichment. If the results of the equation are ( 1, the SLC System is no longer capable of shutting down the reactor with the margin described in Reference 2.

However, the quantity of stored boron includes an additional margin (25%) beyond the amount needed to shut down the reactor to allow for possible imperfect mixing of the chemical solution in the reactor water, leakage, and the volume in other piping connected to the reactor system.

The sodium pentaborate solution (SPB) concentration is allowed to be > 9.2 weight percent provided the concentration and temperature of the sodium pentaborate solution are verified to be within the limits of Figure

3. 1.7-1. This ensures that unwanted precipitation of the sodium pentaborate does not occur.

SR 3.1.7.3 and SR 3. 1.7.5 must be performed every 31 days or within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, of when boron or water is added to the storage tank solution to determine that the boron solution concentration is within the specified limits. The 31 day Frequency of these Surveillances is appropriate because of the relatively slow variation of boron concentration between surveillances.

SR 3. 1.7.3 must be performed within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of discovery that the concentration is > 9.2 weight percent and every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter until the concentration is verified to be z 9.2 weight percent. This Frequency is"appropriate under-these conditions taking into consideration 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 being met.

(continued)

BFN-UNIT 2 B 3.1-43 Amendment

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SLC System B 3.1.7 BASES SURVEILLANCE SR 3.1.7.4 REQUIREMENTS (continued) This Surveillance requires the amount of Boron-10 in the SLC solution tank to be determined every 31 days. The enriched sodium pentaborate solution is made by combining stoichiometric quantities of borax and boric acid in demineralized water. Since the chemicals used have known Boron-10 quantities, the Boron-10 quantity in the sodium pentaborate solution formed can be calculated. This parameter is used as input to determine the volume requirements for SR 3. 1.7. 1. The 31 day Frequency of this Surveillance is appropriate because of the relatively slow variation of boron concentration between surveillances.

SR 3.1.7.6 Demonstrating that each SLC System pump develops a flow rate a 39 gpm at a discharge pressure a 1275 psig ensures that pump performance has not degraded during the fuel cycle.

This minimum pump f1ow rate requirement ensures that, when combined with the sodium pentaborate solution concentration and enrichment requirements, the rate of negative reactivity insertion from the SLC System will adequately compensate for the positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. This test confirms one point on the pump design curve and is indicative of overall performance. The 18 month Frequency is acceptable since inservice testing of the pumps, performed every 92 days, will detect any adverse trends in pump performance.

SR 3.1.7.7 and SR 3.1.7.8 These Surveillances ensure 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 the same manufactured batch as the one fired or from another batch that has been certified by having one of that batch successfu11y fired. The pump and explosive valve be alternated such that both complete flow paths are tested'hould tested every 36 months at alternating 18 month intervals.

The Surveillance may be performed in separate steps to (continued)

BFN-UNIT 2 B 3.1-44 Amendment

il SLC System B 3.1.7 SURVEILLANCE SR 3. 1.7.7 and SR 3. 1.7.8 (continued)

REQUIREMENTS prevent injecting 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 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

Demonstrating that all piping between the boron solution storage tank and the suction inlet to the injection pumps is unblocked ensures that there is a functioning flow path for injecting the sodium pentaborate solution. An acceptable method for verifying that the suction piping is unblocked is to pump from the storage tank to the storage tank. The 18 month Frequency is acceptable since there is a low probability that the subject piping will be blocked due to precipitation of the boron from solution in the piping or by other means.

SR 3.1.7.9 The enriched sodium pentaborate solution is made by combining stoichiometric quantities of borax and boric acid in demineralized water. Isotopic tests on these chemicals to verify the actual B-10 enrichment must be performed at least every 18 months and after addition of boron to the SLC tank in order to ensure that the proper B-10 atom percentage is being used and SR 3. 1.7.5 will be met. The sodium pentaborate enrichment must be calculated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and verified by analysis within 30 days.

REFERENCES 1. 10 CFR 50.62.

2. FSAR, Section 3.8.4.

3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July .23, 1993.

BFN-UNIT 2 B 3.1-45 Amendment

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SDV Vent and Drain Valves B 3.1.8 B 3.1 REACTIVITY CONTROL SYSTEMS B 3. 1.8 Scram Discharge Volume (SDV) Vent and Drain Valves BASES BACKGROUND The SDV vent and drain valves are normally open and discharge any accumulated water in. the SDV to ensure that sufficient volume is available at all times to allow a complete scram. During a scram, the SDV vent and drain valves close to contain reactor water. The SDV is a volume of header piping that connects to each hydraulic control unit (HCU) and drains into an instrument volume. There are two SDVs (headers) and two instrument volumes, each receiving, approximately one half of the control rod drive (CRD) discharges. Each instrument volume is connected to the radwaste system by a drain line containing two valves in series. Each header is connected to a common vent line with two valves in series for a total of four vent valves. The header piping is sized to receive and contain all the water discharged by the CRDs during a scram. The design and functions of the SDV are described in Reference l.

APPLICABLE The Design Basis Accident and transient analyses assume all SAFETY ANALYSES of the control rods are capable of scramming. The acceptance criteria for the SDV vent and drain valves are that they operate automatically to:

a. Close during scram to l.imit the amount of reactor coolant discharged so that adequate core cooling is maintained and offsite doses remain within the limits of 10 CFR 100 (Ref. 3); and

b. Open on scram reset to maintain the SDV vent and drain path open so that there is sufficient volume to accept the reactor coolant discharged during"a-scram.

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 terminated by scram reset or closure of the HCU manual isolation valves. The offsite doses resulting from reactor coolant discharge from the SDV are significantly lower than the bounding doses resulting from a main steam line break outside the secondary containment (Ref. 2) and are well within the limits of (continued)

BFN-UNIT 2 B 3.1-46 Amendment

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SDV Vent and Drain Valves 8 3.1.8 BASES APPLICABLE 10 CFR 100 (Ref. 3). Adequate core cooling is by the SAFETY ANALYSES integrated operation of the Emergency Core Cooling Systems (continued) (Ref. 4). 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 dur'ing a full core scram. To automatically ensure this capacity, a reactor scram (LCO 3.3. 1. 1, "Reactor Protection System (RPS)

Instrumentation" ) is initiated if the SDV water level in the specified setpoint. The instrument volume exceeds a 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 (Ref. 5).

LCO 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 each vent and drain line is 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 open on 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 vent 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 control rod can be withdrawn.- Also, during MODE 5, only a single control rod can be withdrawn from a core cell 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.

(continued)

BFN-UNIT 2 B 3.1-47 Amendment

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SDV Vent and Drain Valves B 3.1.8 ACTIONS The ACTIONS Table is modified by a Note 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 Required Actions may allow for continued operation, and subsequent inoperable SDV lines are governed by subsequent Condition entry and application of associated Required Actions.

A.l When one SDV vent or drain valve is inoperable in one or more lines, the valve must be restored to OPERABLE status within 7 days. The Completion Time is reasonable, given the level of redundancy in the lines and the low probability of a scram occurring during the time the valve(s) are inoperable. The SDV is still isolable since the redundant valve in the affected line is OPERABLE. During these periods, the single failure criterion may not be preserved, and a higher risk exists to allow reactor water out of the primary system during a scram.

B.1 If both valves in a line are inoperable, the line must be isolated to contain the reactor coolant during a scram.

When a line i's isolated, the potential for an inadvertent scram due to high SDV level is increased. Required Action B. 1 is modified by a Note that allows periodic draining and venting of the SDV when a line is isolated.

During these periods, the line may be 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 operator, if a scram occurs with the valve open.

The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 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.

(continued)

BFN-UNIT 2 B 3.1-48 Amendment

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SDV Vent and Drain Valves B 3.1.8 BASES ACTIONS (continued)

If any Required Action and associated Completion Time is not met, the plant must be brought to a NODE in which the LCO does not apply. To achieve this status, the plant must be

.brought to at least NODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reach NODE 3 from full power condi.tions in an orderly manner and without challenging plant systems.

SURVE ILL'ANCE SR 3.1.8.1 REQUIREMENTS During normal operation, the SDV vent and drain valves should be in the open position (except when performing SR 3. 1.8.2) to al,low 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 verification that the valves are in the correct position.

The 31 day Frequency is based on engineering judgment and is consistent with the procedural controls governing valve operation, which ensure correct valve positions.

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 92 day Frequency is based on operating experience and takes into account the level of redundancy in the system design.

(continued).

BFN-UNIT,2 B 3.1-49 Amendment

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SDV Vent and Drain Valves B 3.1.8 BASES

'SURVE IL'LANCE SR 3.1.8.3 RE(UIREMENTS (continued)

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 60 seconds after receipt of a scram signal is acceptable based on the bounding analysis for release of reactor coolant outside containment (Ref. 2). Similarly, after receipt of. a simulated or actual scram reset signal, the opening of the SDV vent and drain valves is verified. The LOGIC. SYSTEM FUNCTIONAL TEST in LCO 3.3. 1. 1 and the scram time testing of control rods in LCO 3. 1.3 overlap this Surveillance to provide complete testing of the: assumed safety function. The 18 month Frequency is based on the need to perform. this Surveillance under the conditions that apply during a plant outage and the potential for an.

unplanned. transient if the Surveillance were performed with the reactor at power., Operating experience has shown these components usually pass the Surveillance when performed at the 18 month'requency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. FSAR, Section 3.4.5.3.1.

2. FSAR, Section 14.6.5.

3. 10 CFR 100.

4. FSAR, Section 6.5.

5. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

BFN-UNIT 2 -B 3.1-50 Amendment

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APLHGR B 3.2.1 B 3.2 POMER DISTRIBUTION LIMITS B 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)

BASES BACKGROUND The APLHGR is a measure of. the average LHGR of all the fuel rods in a fuel assembly at any axial location. Limits on the APLHGR are specified to ensure that the fuel design 1imits identified in Reference I are not exceeded during abnormal operational transients and that the peak cladding temperature (PCT) during the postulated design basis loss of coolant accident (LOCA) does not exceed the limits specified in 10 CFR 50.46.

APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the fuel design limits are presented in References I and 2.

The analytical methods and assumptions used in evaluating Design Basis Accidents (DBAs), abnormal operational transients,,and normal operation that determine the APLHGR limits are presented in References I, 2, 3, and 4.

Fuel design evaluations are performed to demonstrate that the 1% limit on the fuel cladding plastic strain and other fuel design limits described in Reference I are not exceeded during abnormal operational transients for operation with LHGRs up to the operating limit LHGR. APLHGR limits are equivalent to the LHGR limit for each fuel rod divided by the local peaking factor of the fuel assembly. APLHGR limits are developed as a function of exposure and fuel bundle type.

LOCA analyses are then performed to ensure that the above determined APLHGR limits are adequate to meet the PCT and maximum oxidation limits of 10 CFR 50.46. The analysis is performed using calculational models .that are consistent with the requirements of 10 CFR 50, Appendix K. A complete discussion of the analysis code is provided in Reference 5.

The PCT following a postulated LOCA is a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is not strongly influenced by the rod to rod power distribution within an assembly. The APLHGR limits specified are equivalent to the LHGR of the highest powered fuel rod assumed in the LOCA

. ~ analysis divided by its local peaking factor. A (continued)

BFN-UNIT 2 B 3.2-1 Amendment

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APLHGR B 3.2.1 BASES APPLICABLE conservative, multiplier is applied to the LHGR assumed in SAFETY ANALYSES the LOCA analysis to account for the uncerta'inty associated (continued) with the measurement of the APLHGR.

The APLHGR satisfies Criterion 2 of the NRC Policy Statement (Ref. 6)..

LCO The APLHGR limits specified in the COLR are the result of the fuel design, DBA, and'ransient analyses.

APPLICABILITY The APLHGR limits are primarily derived from fuel. design evaluations and LOCA and transient analyses that are as'sumed to occur at high power levels. Design calculations (Ref. 4) and operating experience have shown that as power is reduced, the margin to the .required APLHGR limits, increases.

This trend continues down to the power range of '5% to 15% RTP when entry into MODE 2 occurs. When in MODE 2, the intermediate .range monitor 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 x 25% RTP, the reactor is operating with substantial margin to the APLHGR limits; thus, this LCO is not required.

ACTIONS A. 1 If any APLHGR exceeds the required limits, an assumption regarding an initial condition of the DBA and transient analyses may not be met. Therefore, prompt action should be taken to restore the APLHGR(s) to within the required l.imits such that the plant operates within analyzed conditions,and:

within design limits of the fuel rods. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is sufficient to restore the APL'HGR(s) to within its limits and is acceptable based on the low probability of a transient or DBA occurring simultaneously with the APLHGR out of specification.

(continued)

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APLHGR B 3.2.1 BASES (continued)

ACTIONS B.l (continued)

If the APLHGR 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 < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.1.1 RE(UI REM ENTS APLHGRs are required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is w 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. They are compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> al.lowance after THERMAL POWER a 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

REFERENCES 1. NEDE-24011-P-A-11 "General Electric Standard Application for Reactor Fuel," November 1995.

2. FSAR, Chapter 3.

3. FSAR, Chapter 14.

4. FSAR, Appendix N.

5. NEDC-32484P, "Browns Ferry Nuclear Plant Units 1, 2; and 3, SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis," Revision 1, February 1996.

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

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MCPR B 3.2.2 B 3.2 POWER DISTRIBUTION LIHITS B 3.2.2 MINIMUM CRITICAL POWER RATIO (HCPR)

BASES BACKGROUND MCPR is a ratio of the fuel assembly power that would result in the onset of boiling transition to the actual fuel assembly power. The HCPR Safety Limit (SL) is set such that 99.9% of the fuel rods avoid boiling transition if the limit is not violated (refer to the Bases for SL 2. 1. 1.2). The operating limit HCPR is established to ensure that no fuel damage results during abnormal operational transients.

Although fuel damage does not necessarily occur if a fuel rod actually experienced boiling transition (Ref. 1), the critical power at which boiling transition is calculated to occur has been adopted as a fuel design criterion.

The onset of transition boiling is a phenomenon that is readily detected during the testing of various fuel bundle designs. Based on these experimental data, correlations have been developed to predict critical bundle power (i.e.,

the bundle power level at the onset of transition boiling) for a given set of plant parameters (e.g., reactor vessel pressure, flow, and subcooling). Because plant operating conditions and bundle power levels are monitored and determined relatively easily, monitoring the MCPR is a convenient way of ensuring that fuel failures due to inadequate cooling do not occur.

APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the abnormal operational transients to establish the operating limit HCPR are presented in References 2, 3, 4, and 5. To ensure that the HCPR SL is not exceeded during any transient event that occurs with moderate frequency, limiting transients have been analyzed to determine the largest reduction in critical power. ratio (CPR). The types of transients evaluated are loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease. The limiting transient yields the largest change in CPR (hCPR). When the largest DCPR is added to the HCPR SL, the required operating limit HCPR is obtained.

(continued)

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il'l MCPR 8 3.2.2 APPLICABLE SAFETY ANALYSES (continued)

Flow dependent correction factor for MCPR limits are determined by steady state thermal hydraulic methods with key physics response inputs benchmarked using the three dimensional BWR simulator code (Ref. 6) to analyze slow flow runout transients. The flow dependent correction factor is dependent on the maximum core flow limiter setting in the Recirculation Flow Control System.

The MCPR satisfies Criterion 2 of the NRC Policy Statement (Ref. 7).

LCO The MCPR operating limits spec'ified in the COLR are the resul.t of'he Design Basis Accident (DBA) and transient analysis.

APPL'I CAB IL IT Y The MCPR operating limits are primarily derived, from transient analyses that are assumed to occur at high power levels. Below 25% RTP, the reactor is operating at a minimum recirculation pump speed and the moderator void ratio is small. Surveillance of thermal limits below.

25% RTP is unnecessary due to the large inherent, margin that ensures that the MCPR SL is not exceeded even if a limiting transient occurs. Statistical analyses indicate that the (continued)

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MCPR B 3.2.2 BASES APPLICABILITY nominal value of the initial HCPR expected at 25% RTP is (continued) ) 3.5. Studies of the variation of limiting transient behavior have been performed over the range of power and flow conditions. These studies encompass the range of key actual plant parameter values important to typically limiting transients. The results of these studies demonstrate that a margin is expected between performance and the HCPR requirements, and that margins increase, as power is reduced to 25% RTP. This trend is expected to continue to the 5% to 15% power range when entry into NODE 2 occurs. When in HODE 2, the intermediate range monitor provides rapid scram initiation for any significant power increase transient, which effectively eliminates any HCPR compliance concern. Therefore, at THERHAL POWER levels

< 25% RTP, the reactor is operating with substantial margin to the HCPR limits and this LCO is not required.

ACTIONS A.1 If any HCPR is outside the required limits, an assumption regarding an initial condition of the design basis transient analyses may not be met. Therefore, prompt action should be taken to restore the HCPR(s) to within the required limits such that the plant remains operating within analyzed conditions. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is normally sufficient to restore the HCPR(s) to within its limits and is acceptable based on the low probability of a transient or DBA occurring simultaneously with the HCPR out of specification.

8.1 If the HCPR cannot be restored to within its required limits within the associated Completion Time, the plant must. be brought to a HODE or other specified condition in which the LCO does not apply. To achieve this status, THERHAL POWER must be reduced to < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Completion Time is reasonable, based on operating experience, to reduce THERHAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.

(continued)

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MCPR B 3.2.2 BASES (continued)

SURVEILLANCE SR 3.2.2.1 RE(UIREMENTS The MCPR is required to be initially calculated within 12 hours after THERMAL POWER is a 25% RTP and then every 24 hours thereafter. It is compared to the specified limits in the COLR to ensure that the reactor -is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER a 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

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 determines 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 applicable limits for Option A (scram times of LCO 3.1.4,"Control Rod Scram Times" ) and Option B (realistic scram times) analyses. The parameter r must be determined once within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after each set of scram time tests required by SR 3. 1.4. 1 and SR 3. 1.4.2 because the effective scram speed distribution may change during the cycle. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is acceptable due to the relatively minor changes 'in r expected during the fuel cycle.

REFERENCES 1. NUREG-0562, "Fuel Rod Failure As a Consequence of Departure from Nucleate Boiling or Dryout,"-June 1979.

2. NEDE-24011-P-A-11, "General Electric Standard Application for Reactor Fuel," November 1995.

3. FSAR, Chapter 3.

4. FSAR, Chapter 14.

(continued)

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MCPR B 3.2.2 BASES REFERENCES 5. FSAR, Appendix N.

(continued)

6. NED0-30130-A, "Steady State Nuclear Methods,"

May 1985..

7. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

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LHGR B 3.2.3 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.3 LINEAR HEAT GENERATION RATE (LHGR)

BASES BACKGROUND The LHGR is a measure of the heat generation rate of a fuel rod in a fuel assembly 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 transients. Exceeding the LHGR limit could potentially result in fuel damage and subsequent release of radioactive materials. Fuel design limits are specified to ensure that fuel system damage, fuel rod failure, or inability to cool the fuel does not occur during the anticipated operating conditions identified in Reference l.

APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the fuel system design are presented in References 1 and 2.

The fuel assembly is designed to ensure (in conjunction with the core nuclear and thermal hydraulic design, plant equipment, instrumentation, and protection system) that fuel damage will not result in the release of radioactive materials in excess of the guidelines of 10 CFR, Parts 20, 50, and 100. The mechanisms that could cause fuel damage during operational transients and that are considered in fuel evaluations are:

a. Rupture of the fuel rod cladding caused by strain from the relative expansion of the UO, pellet; and b; Severe overheating of the fuel rod cladding caused by inadequate cooling.

A value of 1% plastic strain of the fuel cladding has been.

defined as the limit below which fuel damage caused by overstraining of the fuel cladding is not expected to occur (Ref. 3).

Fuel design evaluations, have been performed and demonstrate that the 1% fuel cladding plastic strain design limit is not exceeded during continuous operation with LHGRs up to the (continued)

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LHGR B 3.2.3 BASES APPLICABLE operating limit specified in the COLR. The analysis also SAFETY ANALYSES allowances for short term transient operation above 'ncludes (continued) the operating limit to account for abnormal operational transients, plus an allowance for densification power spiking.

The 'LHGR satisfies Criterion 2 of the NRC Policy Statement (Ref. 4).

LCO The LHGR is a basic assumption in the fuel design analysis.

The fuel has been designed to operate at rated core power with sufficient design margin to the LHGR calculated to cause a 1% fuel cladding plastic strain. The operating limit to accomplish this objective is specified in the COLR.

APPLICABILITY The LHGR limits are derived from fuel design analysis that is limiting at high power level conditions. At core thermal power levels < 25% RTP, 'the reactor is operating with a substantial margin to the LHGR limits and, therefore, the Specification is only required when the reactor is operating at a 25% RTP.

ACTIONS A.l If any LHGR exceeds its required limit, an assumption regarding an initial condition of the fuel design analysis is not met. Therefore, prompt action should:be taken to restore the LHGR(s) to within its required limits such that the plant is operating within analyzed conditions. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is. normally sufficient to restore the LHGR(s) to within its limits and is acceptable based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LHGR out of specification.

B.1 If the LHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the (continued)

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LHGR B 3.2.3 ACTIONS B. 1 (continued)

LCO does not apply. To,achieve this status, THERMAL POWER is reduced to < 25% RTP within. 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER TO < 25% RTP in, an orderly manner and without. challenging plant systems.

SURVEILLANCE SR 3.2.3.l RE(UIREMENTS The LHGR is required to 'be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is a 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. It is compared,to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the: slow changes in power distribution during normal operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER a,25% RTP is achieved is acceptable given the large inherent

'margin to operating limits at lower power levels.

REFERENCES 1. FSAR,. Chapter 14.

.2. FSAR, Chapter 3.

3. NUREG-0800, Standard Review Plan 4.2, Section II.A.2(g), Revision 2, July 1981.

4. ,NRC No.93-102,, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

BFN-UNIT 2 B 3.2-11 Amendment

0 APRM Gain and Setpoints B 3.2.4 B 3.2 POWER DISTRIBUTION L'IHITS B 3.2.4 Average Power Range Monitor (APRH) Gain and Setpoints BASES BACKGROUND The OPERABILITY of the APRMs and their setpoints is an initial condition of all safety analyses that assume rod insertion upon reactor scram. Applicable GDCs are GDC 10, "Reactor Design," GDC 13, "Instrumentaf.ion and Control,"

GDC 20, "Protection System Functions," and GDC 23, "Protection System Failure Modes" (Ref. 1). This LCO is provided to require the APRH gain or APRH flow biased scram setpoints to be adjusted when operating under conditions of excessive power peaking to maintain acceptable margin to the fuel cladding integrity Safety Limit (SL) and the fuel cladding 1% plastic strain limit.

The condition of excessive power peaking is determined by the ratio of the actual power peaking to the limiting power peaking at RTP. This ratio is equal to the ratio of the core limiting HFLPD to the Fraction of RTP (FRTP), where FRTP is the measured THERMAL POWER divided by the RTP.

Excessive power peaking exists when:

NFLPD

) 1, FRTP indicating that HFLPD is not decreasing proportionately to the overall power reduction, or conversely, that power peaking is increasing. To maintain margins similar to those at RTP conditions, the excessive power peaking is compensated by a gain adjustment on the APRHs or adjustment of the APRM setpoints. Either of these adjustments has effectively the same result as maintai'ning HFLPD less than or equal to FRTP and thus maintains RTP margins for APLHGR and HCPR.

The normally selected APRM setpoints position the, scram above the upper bound of the normal power/flow operating region that has been considered in the design of the fuel rods. The setpoints are flow biased with a slope that approximates the upper flow control line, such that an approximately constant margin is maintained between the flow biased trip level and the upper operating boundary for core flows in excess of about 45% of rated core flow. In the range of infrequent operations below 45% of rated core flow, (continued)

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APRM Gain and Setpoints B 3.2.4 BASES BACKGROUND the margin to scram is reduced .because of the nonlinear core (continued) flow versus drive flow relationship. The normally selected APRM setpoints are supported by the analyses presented in References 1 and 2 that concentrate on events initiated from rated conditions. Design experience .has shown that minimum deviations occur within expected margins to operating limits (APLHGR and MCPR), at rated conditions for normal power distributions. However, at other than rated conditions, control rod patterns can be established that significantly reduce the margin to thermal limits. Therefore, the flow biased APRH scram setpoints may be reduced during operation when the combination of THERMAL POWER and HFLPD indicates an excessive power peaking distribution.

The APRH neutron flux signal is also adjusted to more closely follow the fuel cladding heat flux during power transients. The APRH neutron flux signal is a measure of the core thermal power during steady state operation.

During power transients, the APRM signal leads the actual core thermal power response because of the fuel thermal time constant. Therefore, on power increase transients, the APRH signal provides a conservatively high measure of core thermal power. By passing the APRM signal through an electronic filter with a time constant less than, but approximately equal to, that of the fuel thermal time constant, an APRM transient response that more closely follows actual fuel cladding heat flux is obtained, while a conservative margin is maintained. The delayed response of the filtered APRM signal allows the flow biased APRM scram level's to be positioned closer to the upper bound of the normal power and flow range, without unnecessarily causing reactor scrams during short duration neutron flux spikes.

These spikes can be caused by insignificant transients such as performance of main steam line valve surveillances or momentary flow increases of only several percent.

APPLICABLE The acceptance criteria for the APRM gain or setpoint SAFETY ANALYSES adjustments are that acceptable margins (to APLHGR and HCPR) be maintained to the fuel cladding integrity SL and the fuel cladding 1% plastic strain limit.

FSAR safety analyses (Refs. 2 and 3) concentrate on the rated power condition for. which the minimum expected margin to the operating limits (APLHGR and MCPR) occurs.

(continued)

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APRH Gain and Setpoints B 3.2.4 APPLICABLE LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE SAFETY ANALYSES (APLHGR)," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (continued) (MCPR)," limit the initial margins to these operating limits at rated conditions so that specified acceptable fuel design limits are met during transients initiated from rated conditions. At initial power level's less than rated levels, the margin degradation of either the APLHGR or the HCPR during a transient can be greater than at the rated condition event. This greater margin degradation during the transient is primarily offset by the larger initial margin to limits at the lower than rated power levels. However, power distributions can be hypothesized that would result in reduced margins to the pre-transient operating limit. When combined with the increased severity of certain transients at other than rated conditions, the SLs could be approached.

At substantially reduced power .levels, highly peaked power distributions could be obtained that could reduce thermal margins to the minimum levels required for transient events.

To prevent or mitigate such situations, either the APRH gain is adjusted upward by the ratio of the core limiting HFLPD to the FRTP,, or the flow biased APRH scram level is required to be reduced by the ratio of FRTP to the core limiting MFLPD. Either of these adjustments effectively counters the increased severity of some events at other than rated conditions by proportionally increasing the APRH gain or proportionally lowering the flow biased APRH scram setpoints, dependent on the increased peaking that may be encountered.

The APRH gain and setpoints satisfy Criteria 2 and 3 of the NRC Policy Statement (Ref. 4).

LCO Meeting any one of the following conditions ensures acceptable operating margins for events described above:

a. Limiting excess power peaking;

b. Reducing the APRM flow biased neutron flux upscale scram setpoints by multiplying the APRH setpoints by the ratio of FRTP and the core limiting value of HFLPD; or (continued)

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APRM Gain and Setpoints B 3.2.4 BASES LCO c. Increasing APRH gains to cause the APRH to read (continued) a 100 times HFLPD (in %). This condition is to account for the reduction in margin to the fuel cladding integrity SL and the fuel cladding 1% plastic strain limit.

HFLPD is the ratio of the limiting LHGR to the LHGR limit for the specific bundle type. As power is reduced, if the design power distribution is maintained, HFLPD is reduced in proportion to the reduction in power. However., if power peaking increases above the design value, the HFLPD is not reduced in proportion to the reduction in power. Under these conditions, the APRM gain is adjusted upward or the APRH flow biased scram setpoints are reduced accordingly.

When the reactor is operating with peaking less than the design value, it is not necessary to modify the APRM flow biased scram setpoints. Adjusting APRM gain or setpoints is equivalent to HFLPD less than or equal to FRTP, as stated in the LCO.

For compliance with LCO Item b (APRH setpoint adjustment) or Item c (APRM'gain adjustment), only APRHs required to be OPERABLE per LCO 3.3. 1. 1, "Reactor Protection System (RPS)

Instrumentation," are required to be adjusted. In addition, each APRH may be allowed to have its gain or setpoints adjusted independently of other APRHs that are having their gain or setpoints adjusted.

APPLICABILITY The HFLPD limit, APRH gain adjustment, and APRH flow biased scram and associated setdowns are provided to ensure that the fuel cladding integrity SL and the fuel cladding 1% plastic strain limit are not violated during design basis transients. As discussed in the Bases for LCO 3.2. 1 and LCO 3.2.2, sufficient margin to these limits exists below 25% RTP and, therefore, these requirements -are only necessary when the reactor is operating at a 25% RTP.

ACTIONS A.l If the APRH gain or setpoints are not within limits while the HFLPD has exceeded FRTP, the margin to the fuel cladding integrity SL and the fuel cladding 1% plastic strain l,imit (continued)

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APRM Gain and Setpoints B 3.2.4 BASES ACTIONS A. 1 (continued) may be reduced. Therefore, prompt action should'e taken to restore the MFLPD to within its required limit or make acceptable APRH adjustments such that the plant is operating within the assumed margin of the safety analyses.

The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Completion Time is normally sufficient to restore either the MFLPD to within limits or the APRH gain or setpoints to within limits and is acceptable based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LCO not met.

B.l If MFLPD 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 < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.4.1 and SR 3.2.4.2 RE(UIREHENTS The HFLPD is required to be calculated and compared with FRTP, or APRH gains or setpoint, to ensure that the reactor is operating within the assumptions of the safety analysis.

These SRs are only required to determine the,HFLPD and, assuming HFLPD is greater than FRTP, the appropriate gain or setpoint, and are not intended to be a CHANNEL FUNCTIONAL TEST for the APRH gain or flow biased neutron flux scram circuitry. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency o'f SR 3.2.4. 1 is chosen to coincide with the determination of other thermal limits, specifically those for the APLHGR (LCO 3.2. 1). The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of .the slowness of changes in power distribution during normal operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER a 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

(continued)

BFN-UNIT 2 8 3.2-16 Amendment

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APRH Gain and Setpoints B 3.2.4 BASES SURVEIL'LANCE SR 3.2.4. 1 and SR 3.2.4.2 (continued)

REg UIREHENTS The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 'Frequency of SR 3.2.4.2 requires a more frequent verification than if HFLPD is less than or equal to FRP.

When HFLPD is greater than FRP, more rapid changes in power distribution, are typically expected.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10, GDC 13, GDC 20, and GDC 23.

2. FSAR, Chapter 14.

3. FSAR, Chapter 3.

4. NRC No.,93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

BFN-UNIT 2 B 3.2-17 Amendment

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RPS Instrumentation 8 3.3.1.1 B 3.3, INSTRUMENTATION B 3.3.1. 1 Reactor Protection System (RPS) Instrumentation BASES BACKGROUND The RPS initiates a, reactor scram when one or more monitored parameters exceed their specified limits, to preserve the integrity of the fuel cladding and the Reactor Coolant System (RCS) .and minimize the energy that must be absorbed following a loss of coolant accident (LOCA). This can be accomplished either automatically or manually.

The protection and monitoring functions of the RPS have been designed to ensure safe operation of the reactor. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RPS, as well as LCOs on other reactor system- parameters and equipment performance. The LSSS are defined in this Specification as the Allowable Values, which, in conjunction with the LCOs, establish the threshold for protective system action to prevent exceeding acceptable limits, including Safety Limits (SLs) during Design Basis Accidents (DBAs).

The RPS, as described in the FSAR, Section 7.2 (Ref. 1),

includes sensors, relays, bypass circuits, and switches that are necessary to cause initiation of a reactor scram.

Functional diversity is provided by monitoring a wide 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 l,ine isolation valve position, turbine control valve (TCV) fast closure (indicated by TCV low hydraulic pressure) trip oil pressure, turbine stop valve (TSV) position, drywell pressure, scram pilot air header pressure, and scram discharge volume (SDV) water level, as well as reactor mode switch in shutdown position, manual, and RPS channel test switch scram signals.

There are at least four redundant sensor input signals from each of these. parameters (with the exception of the reactor mode switch in shutdown and manual scram signals). Host channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints.. When the setpoint is exceeded, the channel output relay deenergizes actuates, which then outputs an RPS trip signal to the trip logic.

(continued)

BFN-UNIT 2 B 3.3-1 Amendment

0 RPS Instrumentation B 3.3.1.1 BASES BACKGROUND The RPS is comprised of two independent trip systems (continued) (A and B) with two logic channels in each trip system (logic channels Al and A2, Bl and B2) as shown in Reference 1. The outputs of the logic channels in a trip system are combined in a one-out-of-two logic so that either channel can trip the associated trip system. The tripping of both trip systems will produce a reactor scram. This logic arrangement is referred to as a one-out-of-two taken twice logic. 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 will 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 solenoids, air bleeding. off, scram valves opening, and control rod scram.

The backup scram valves, which energize on a full scram signal to depressurize the scram air header, are also controlled by the RPS. Additionally, the RPS System controls the SDV vent and drain valves such that when both trip systems trip, the SDV vent and drain valves close to isolate the SDV.

APPLICABLE The actions of the RPS are assumed in the safety analyses of SAFETY ANALYSES, References 1, 2, and 3. The RPS initiates a reactor scram LCO, and when monitored parameter values exceed the Allowable Values, APPLICABILITY specified by the setpoint methodology and listed in Table 3.3. 1. 1-1 to preserve the integrity of the fuel (continued)

BFN-UNIT 2 B 3.3-2 Amendment

0 RPS Instrumentation B 3.3.1.1 APPLICABLE cladding, the reactor coolant pressure boundary (RCPB), and SAFETY ANALYSES, the containment by minimizing the energy that must be LCO, and absorbed following a LOCA.

APPLICABILITY (continued) RPS instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 10). Functions not specifically credited in the accident analysis are retained for the overall 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 3.3.1.1-1. Each Function must have a required number of OPERABLE channels per RPS trip system, with their setpoints within the specified Allowable Value, where appropriate. The setpoint is calibrated consistent with applicable setpoint methodology assumptions (nominal trip setpoint).

Allowable Values are specified for each RPS Function specified in the Table. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the actual setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. A channel is inoperable if its actual trip setpoint is not within its required Allowable 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 analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibratio'n, process, and some of the instrument errors.

The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe (continued)

BFN-UNIT 2 B 3.3-3 Amendment

0 0

RPS Instrumentation B 3.3.1.1 APPLICABLE environmental effects (for channels that must function in SAFETY ANALYSES, harsh environments as defined by 10 CFR 50.49) are accounted LCO, and for.

APPLICABILITY (continued) 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 NODES or other specified conditions in the Table, which may require an RPS trip to mitigate the consequences of a design basis accident or transient. To ensure a reliable scram function, a combination of Functions are required in each NODE to provide primary and diverse initiation signals.

The only MODES specified in Table 3.3.1.1-1 are NODES 1 (which encompasses > 30%%u RTP) 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 fully inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1) does not allow any control 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 condition, the required SDM (LCO 3.1.1) and refuel position one-rod-out interlock (LCO 3.9.2) ensure that no event requiring RPS will occur.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

Intermediate Ran e Monitor IRH

l. , Intermediate an e Mo ito Neutron Fl x Hi h The IRMs monitor neutron flux levels from the upper range of the source range monitor (SRH) to the lower range of the average power range monitors (APRHs). The IRHs are capable of generating trip signals that can be used to prevent fuel damage resulting from abnormal operating transients in the intermediate power range. In this power range, the most (continued)

BFN-UNIT 2 B 3.3-4 Amendment

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RPS Instrumentation B 3.3.1.1 BASES APPLICABLE ntermed te a e o to Neut o x-SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY significant source of reactivity change is due to control rod withdrawal. The IRM mitigates control rod withdrawal error events and is diverse from the rod worth minimizer (RWM), which monitors and controls the movement of control rods at low power. The RWM prevents the withdrawal of an out of sequence control rod during startup that could result in an unacceptable neutron flux excursion (Ref. 2). The IRM provides mitigation of the neutron flux excursion. To demonstrate the capability of the IRM System to mitigate control rod withdrawal events, generic analyses have been performed (Ref. 3) to evaluate the consequences of control rod withdrawal events during startup that are mitigated only by the IRM. This analysis, which assumes that one IRM channel in each trip system is bypassed, demonstrates that the IRMs provide protection against local control rod withdrawal errors and results in peak fuel energy depositions below the 170 cal/gm fuel failure threshold criterion.

The IRMs are also capable of limiting other reactivity excursions during startup, such as cold water injection events; although no credit is specifically assumed.

The IRM .System is divided into two groups of IRM channels, with four IRM channels inputting to each trip system. The analysis of Reference 3 assumes that one channel in each trip system is bypassed. Therefore, six channels with three channels in each trip system are required for IRM OPERABILITY. to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This trip is active in each of the 10 ranges of the IRM, which must be selected by the operator to maintain the neutron flux within the monitored level of an IRM range.

The analysis of Reference 3 has adequate conservatism to permit an IRM Allowable Value of 120 divisions of a 125 division scale.

The Intermediate Range Monitor Neutron Flux- High Function must be OPERABLE during MODE 2 when control rods may be withdrawn and the potential for criticality exists. In HODE 5, when a cell with fuel has its control rod withdrawn, the IRMs provide monitoring for and protection against (continued)

BFN-UNIT 2 B 3.3-5 Amendment

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RPS Instrumentation 8 3.3.1.1 BASES APPLICABLE I termediate Ran e Mo itor eutro ux- i SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY unexpected reactivity excursions. In NODE 1, the APRN System and the RBM provide protection against control rod withdrawal error events and the IRMs are not required.

b t ed te Ran e Mo to o This trip signal provides assurance that a minimum number of IRNs are OPERABLE. Anytime an IRN mode switch is moved to any position other than "Operate," the detector voltage drops below a preset level, or when a module is not plugged in, an inoperative trip signal will be received by the RPS unless the IRN is bypassed. Since only one IRM in each trip system may be bypassed, only one IRN in eqch RPS trip system may be inoperable without resulting in an RPS trip signal.

This Function was riot 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.

Six channels of Intermediate Range Monitor- Inop with three channels in each trip system are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.

Since this Function is not assumed .in the safety analysis, there is no Allowable Value for this Function.

This Function is required to be OPERABLE when the Intermediate Range Monitor Neutron Flux-High Function is required.

Avera e Power Ran e Monitor 2.a. vera e Power Ran e o itor Neutron F ux Hi h Setdown The APRN channels receive input signals from the local power range monitors (LPRHs) within the reactor core to provide an indication of the power distribution and local power changes. The APRN channels average these LPRN signals to provide a continuous indication of average reactor power from a few percent to greater than RTP. For operation at (continued)

BFN-UNIT 2 B 3.3-6 Amendment

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RPS Instrumentation B 3.3.1.1 BASES APPLICABLE vera e Powe Ran e o ito e t o u h SAFETY ANALYSES, ~Setdo (continued)

LCO, and APPLICABILITY low power (i.e., NODE 2), the Average Power Range Monitor Neutron Flux-High, Setdown Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operating transients in this power range. For most operation at low power levels, the Average Power Range Monitor Neutron Flux- High, Setdown Function will provide a secondary scram to the .Intermediate Range Monitor Neutron Flux-High Function because of the relative setpoints. With the IRNs at Range 9 or 10, it is possible that the Average Power Range Monitor Neutron Flux-High, Setdown Function will provide the primary trip signal for a corewide increase in power.

No specific safety analyses take direct credit for the Average Power Range Monitor Neutron Flux-High, Setdown Function. However, this Function indirectly ensures that before the reactor mode switch is placed in the run position, reactor power does not exceed 25/. RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow.

Therefore, it indirectly prevents fuel damage during significant reactivity increases with THERMAL POWER

< 25K RTP.

The APRN System is divided into two groups of channels with three APRN channel inputs to each trip system. The system is designed to allow one channel in each trip system to be bypassed. Any one APRN channel in a trip system can cause the associated trip system to trip. Four channels of Average Power Range Monitor Neutron Flux-High, Setdown with two channels in each trip system are required to be OPERABLE to ensure that no single failure will preclude a scram from this Function on a valid signal. In addition, to provide adequate coverage of the entire core, at least 14 LPRN inputs are required for each APRN channel, with at least two LPRN inputs from each of the four axial levels at which the LPRNs are located.

The Allowable Value is based on preventing significant increases in power when THERMAL POWER is < 25% RTP.

The Average Power Range Monitor Neutron Flux-High, Setdown Function must be OPERABLE during NODE 2 when control rods may be withdrawn since the potential for criticality exists.

(continued)

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RPS Instrumentation B 3.3.1.1 BASES APPLICABLE .a vera e 'Power a e Mon tor t o F xi SAFETY ANALYSES, Setdown (continued)

LCO, and APPLICABILITY In MODE 1, the Average Power Range Monitor Neutron Flux-High Function provides protection against reactivity transients and the RWM and rod, block monitor, protect against control rod withdrawal error events.

.b. Avera e Power an e onitor Flow Biased S'ated T ermal Powe Hi h The Average Power Range Monitor Flow Biased Simulated Thermal Power-High Function monitors neutron flux to approximate the THERMAL POWER being transferred to the reactor coolant. The APRM neutron flux is electronically filtered with a time constant representative of the fuel heat transfer dynamics 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 proportional 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 or equal to the Average Power Range Monitor Fixed Neutron Flux- High Function Allowable Value. The 'Average Power Range 'Monitor Flow Biased Simulated Thermal Power-High Function provides protection against transients where THERMAL POWER increases slowly (such as 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 THERMAL POWER increase does not significantly lag the neutron flux response and, because of a lower trip setpoint, will initiate a scram before the high neutron flux scram. For rapid neutron flux increase events, the THERMAL POWER lags the neutron flux and the Average Power Range Monitor Fixed Neutron Flux-High Function will provide a scram signal before the Average Power Range Monitor Flow Biased Simulated Thermal Power-High Function setpoint is exceeded.

The APRM System is divided into two groups of channels with three APRM channel inputs to each trip system. The system is designed to allow one channel in each trip system to be bypassed. Any one APRM channel in a trip system can cause the associated trip system to trip. Four channels of (continued)

BFN-UNIT 2 B 3.3-8 Amendment

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RPS Instrumentation B 3.3.l.l APPLICABLE 2.b. Avera e Power Ran e Monitor Flow Biased Simulated SAFETY ANALYSES, Thermal Power- Hicih (continued)

LCO, and APPLICABILITY Average Power Range Monitor Flow Biased Simulated Thermal Power- High 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. In addition, to provide adequate coverage of the entire core, at least 14 LPRM inputs are required for each APRM channel, with at least two LPRM inputs from each of the four axial levels at which the LPRMs are located. Each APRM channel receives a total drive flow signal representative of total core flow.

The total drive flow signals are generated by two flow units, one of which supplies signals to the trip system A APRMs, while the other one supplies signals to the trip system B APRMs. Each flow unit signal is provided by summing up the flow signals from the two recirculation loops. Each required Average Power Range Monitor Flow Biased Simulated Thermal Power- High channel requires an input from its associated OPERABLE flow unit.

The clamped Allowable Value is based on analyses that take credit for the Average Power Range Monitor Flow Biased Simulated Thermal Power-High Function for the mitigation of the loss of feedwater heating event. The THERMAL POWER time constant of < 7 seconds is based on the fuel heat transfer dynamics and provides a signal proportional to the THERMAL POWER. The term "W" in the equation for determining the Allowable Value is defined as total recirculation flow in percent of rated.

The Average Power Range Monitor Flow Biased Simulated Thermal Power- High Function is required to be OPERABLE in MODE I when there is the possibility of generating excessive THERMAL POWER and potentially exceeding the SL applicable to high pressure and core flow conditions (MCPR SL). During NODES 2 and 5, other IRM and APRN Functions provide protection for fuel cladding integrity.

2.c. Avera e Power Ran e Monitor Fixed Neutron Flux-~Hi h The APRM channels provide the primary indication of neutron flux within the core and respond almost instantaneously to neutron flux increases. The Average Power Range Monitor

Fixed Neutron Flux High Function is capable of generating a (continued)

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RPS Instrumentation B'.3.1.1 BASES APPLICABLE 2,c Avera e Powe n e onitor ixed eutron F u SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY trip signal to prevent fuel damage or excessive RCS pressure. For the overpressurization protection analysis of Reference 4, the Average Power Range Monitor Fixed Neutron Flux-High Function is assumed to terminate the main steam isolation valve (MSIV) closure event and, along with the safety/relief valves (S/RVs), limits the peak reactor pressure vessel (RPV) pressure to less than the ASME Code limits. The control rod drop accident (CRDA) analysis (Ref. 5) takes credit for the Average Power Range Monitor Fixed Neutron Flux-High Function to terminate the CRDA.

The APRM System is divided into two groups of channels with three APRM channels inputting to each trip system. The system is designed to allow one channel in each trip system to be bypassed. Any one APRM channel in a trip system can cause the associated trip system to trip. Four channels of Average Power Range Monitor Fixed Neutron Flux- High 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. In addition, to provide adequate coverage of the entire core, at least 14 LPRM inputs are required for each APRM channel, with at least two LPRM inputs from each of the four axial levels at which the LPRMs are located.

The Allowable Value is based on the .Analytical Limit assumed in the CRDA analyses.

The Average Power Range Monitor Fixed Neutron Flux-High Function is required to be OPERABLE in MODE 1 where the potential consequences of the analyzed transients could result in the SLs (e.g., MCPR and RCS pressure) being exceeded. Although the Average Power Range Monitor Fixed Neutron Flux-High Function is assumed in the CRDA analysis, 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 IRM trips, provides adequate protection. Therefore, the Average Power Range Monitor Fixed Neutron Flux-High Function is not required in MODE 2.

(continued)

BFN-UNIT 2 B 3.3-10 Amendment

il RPS Instrumentation B 3.3.1.1 APPLICABLE d ve a e Power Ran e Mo ito Oow scale SAFETY ANALYSES, LCO, and This signal ensures that there is adequate Neutron APPLICABILITY Monitoring System protection if the reactor mode switch is

,(continued) placed in the run position prior to the APRHs coming on scale. With the reactor mode switch in run, an APRM downscale signal coincident with an associated Intermediate Range Monitor Neutron Flux-High or Inop signal generates a 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.

The APRM System is divided into two groups of channels with three inputs into each trip system. The system is designed to allow one channel in each trip system to be bypassed.

Four channels of Average Power Range Monitor-Downscale 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 failure will preclude a scram from this Function on a valid signal. The Intermediate Range Monitor Neutron Flux-High and Inop Functions are also part of the OPERABILITY of the Average Power Range Monitor-Downscale

'Function (i.e., if either of these IRN Functions cannot send a signal to the Average Power Range Monitor-Downscale Function, the associated Average Power Range Monitor -Downscale channel is .considered inoperable).

The Allowable Value is based upon ensuring that the APRNs are in the linear scale range when transfers are made between APRNs and IRNs.

This Function is required to be OPERABLE in NODE 1 since this is when the APRNs are the primary indicators of reactor power.

2.e. vera e Power Ran e Monitor Ino This signal provides assurance that a minimum number of APRMs are OPERABLE. Anytime an APRH mode switch is moved to any position other than "Operate," an APRN module is unplugged, the electronic operating voltage is low, or the APRH has too few LPRH inputs (< 14), an inoperative trip signal will be received by the RPS,'nless the APRN is bypassed. Since only one APRN in each trip system may be bypassed, only one APRN in each trip system may be (continued)

BFN-UNIT 2 B 3.3-11 Amendment

il RPS Instrumentation B 3.3.1.1 APPLICABLE 2.e; Avera e Powe an e Monitor no (continued)

SAFETY ANALYSES, LCO, and inoperable without resulting in an RPS trip signal. This APPLICABILITY 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.

Four channels of Average Power Range Monitor- Inop with two channels in each trip system are required to be OPERABLE to ensure that no single failure will preclude a scram from this Function on a valid signal.

There is no Allowable Value for this Function.

This Function is required to be OPERABLE in the NODES where the APRM Functions are required.

3 eactor Vesse Steam Dome Press e i An increase in the RPV pressure during reactor operation compresses the steam voids and results in a positive 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. The Reactor Vessel Steam Dome 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, reactor scram (the analyses conservatively assume scram on the Average Power Range Monitor Fixed'eutron Flux-High signal, not the Reactor Vessel Steam Dome Pressure -High signal), along with the S/RVs, limits the peak RPV pressure to less than the ASHE Section III Code limits.

High reactor pressure signals are initiated from four pressure transmitters that sense reactor pressure. The Reactor Vessel Steam Dome Pressure-High Allowable Value is chosen to provide a sufficient margin to the ASME Section III Code limits during the event.

Four channels of Reactor Vessel Steam Dome Pressure-High Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to

('continued)

BFN-UNIT 2 B 3.3-12 Amendment

0 RPS Instrumentation 8 3.3.1.1 APPLICABLE 3. Reactor Vessel Steam Dome Pressure- hicih (continued)

SAFETY ANALYSES, LCO, and ensure that no single instrument fai1ure will preclude a APPLICABILITY scram from this Function on a va1id signal. The Function is required to be OPERABLE in NODES 1 and 2 when the RCS is pressurized and the potential for pressure increase exists.

4. Reactor Vessel Water Level - Low Level 3 Low RPV water level indicates the, capability to cool the fuel may be threatened. Should RPV water level decrease 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 Vessel Water Level Low, Level 3 Function is assumed in the analysis of the recirculation line break (Ref. 6). The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the Emergency Core Cooling Systems (ECCS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

Reactor Vessel Water Level Low, Level 3 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, 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 (a) during normal operation the steam dryer skirt is not uncovered (this protects available recirculation pump net positive suction head (NPSH) from significant carryunder), and (b) for transients involving loss of all normal feedwater flow, initiation of the low pressure ECCS subsystems at Reactor Vessel Water- Low Low Low, Level 1 will not be required.

The .Function is required, in NODES 1 and 2 where considerable energy exists in the RCS resulting in the limiting transients and accidents. ECCS initiations at Reactor (continued)

BFN-UNIT 2 B 3.3-13 Amendment

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RPS Instrumentation B 3.3.1.1 BASES APPLICABLE actor esse Wate L'eve ow eve 3 (continued)

SAFETY ANALYSES, LCO, and Vessel Water Level Low Low, Level 2 and Low Low Low, APPLICABILITY Level 1 provide sufficient protection for level transients in all other NODES.

5. ai Stea Iso at o Valve C os e HSIV 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 Hain Steam Isolation Valve-'Closure signal before the HSIVs are completely closed in anticipation of the complete loss of the normal heat sink and subsequent overpressurization transient. However, for the overpressurization protection analysis of Reference 4, the Average Power Range Monitor Fixed Neutron Flux- High Function, along with the S/RVs, limits the peak RPV pressure to less than the ASME Code limits. That. is, the direct scram on position switches for

,MSIV closure events is not assumed in the overpressurization analysis. Additionally, MSIV closure is assumed in the transients analyzed in Reference 7 (e.g., low steam line pressure, manual closure of MSIVs, high steam line flow).

The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the l-imits of 10 CFR 50.46.

NSIV closure signals are initiated from position switches located on each of the eight HSIVs. Each HSIV has two position switches; one inputs to RPS trip system A while the other inputs to RPS trip system B. Thus, each RPS trip system receives an input from eight Hain Steam Isolation Valve Closure channels, each consisting of one position switch. The logic for the Hain Steam Isolation Valve- Closure Function is arranged such that either the inboard or outboard valve on three or more of the main steam lines must close in order for a scram to occur.

The Hain 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.

(continued)

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RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 5. ai Steam Isolat o 'ive Closu e (continued)

SAFETY ANALYSES, LCO, and Sixteen channels of the Hain Steam Isolation Valve- Closure APPLICABILITY Function, with eight channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude the scram from this Function on a valid signal. This Function is only required in NODE 1 since, with the HSIVs open and the heat generation rate high, a pressurization transient can occur if the NSIVs close. In NODE 2, the heat generation rate is low enough so that the other diverse RPS functions provide sufficient protection.

6 e ess e High pressure in the drywell could indicate a break in the RCPB. A reactor scram is initiated to minimize the possibility of fuel damage and to reduce the amount of energy being added to the coolant and the drywell. The Drywell Pressure-High Function is a secondary scram signal to Reactor Vessel Mater Level Low, Level 3 for LOCA events inside the drywell. However, no credit is taken for a scram initiated from this Function for any of the DBAs analyzed in the FSAR. 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.

High drywell pressure signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible and indicative of.a LOCA inside primary containment.

Four channels of Drywell Pressure-High 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 Function is required in NODES 1 and 2 where considerable energy exists in the RCS, resulting in the limiting transients and accidents.

(continued)

BFN-UNIT 2 B 3.3-15 Amendment

ik RPS Instrumentation B 3.3.1.1 APPLICABLE 7a b Scr 'sc ar e Volume Water vel SAFETY ANALYSES, LCO, and The SDV receives the water displaced by the. motion of the APPLICABILITY CRD pistons during a reactor scram. Should this volume (continued) 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 volume is still sufficient to accommodate the water from a full core scram. The two types of Scram Discharge Volume Water Level -High Functions are an input to the RPS logic. No credit is taken for a scram initiated from these Functions for any of the design basis accidents or transients analyzed in the FSAR. However, they are retained to ensure the RPS remains OPERABLE.

SDV water level is measured by two diverse methods. The level in each of the two SDVs is measured by two float type level switches and two thermal probes for a total of eight level signals. The outputs of these devices are arranged so that there is a signal from a level switch and a thermal probe to each RPS logic channel. The level measurement instrumentation satisfies the recommendations of Reference 8.

The Allowable Value is chosen low enough to ensure that there, is sufficient volume in the SDV to accommodate the water from a full scram.

Four channels of each type of Scram Discharge Volume Water Level -High Function, with two channels of each type in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from these Functions on a valid signal. These Functions are 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 specified conditions when control rods are withdrawn. At all other times, this Function may be bypassed.

8. Turbine Sto Valve Closure Closure of the TSVs results in the loss of a -heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated at the start of TSV closure in anticipation of (continued)

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RPS Instrumentation B '3.3.1.1 BASES APPLICABLE 8 rb e Sto V lve C osure SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY the transients that would result from the closure of these valves. The Turbine Stop Valve-Closure Function is the primary scram signal for the turbine trip event analyzed in Reference 7. For this event, the reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the End of Cycle Recirculation Pump Trip (EOC-RPT) System, ensures that the MCPR SL is not exceeded.

Turbine Stop Valve-Closure signals are initiated from position switches located on each of the four TSVs. Two independent position switches are associated with each stop valve. One of the two switches provides input to RPS trip system A; the other, to RPS trip system B. Thus, each RPS trip system receives an input from four Turbine Stop

-

Valve Closure channels, each consisting of one position switch. The logic for the Turbine Stop Valve-Closure Function is such that three or more TSVs must be closed to produce a scram. This Function must be -enabled at THERMAL POWER h 3K RTP. This is. normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening 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 any three TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is > 3Ã RTP. This Function is not required when THERMAL 'POWER is (

the Reactor Vessel Steam Dome Pressure-High and the 3M'TP'ince Average Power Range Monitor Fixed Neutron Flux-High Functions are. adequate to maintain the necessary safety margins.

(continued)

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RPS Instrumentation B 3.3.1.1 APPLICABLE 9. Turb e Control Valve ast Closure Tri 0 SAFETY ANALYSES, essure ow LCO, and APPLICABILITY Fast closure of the TCVs results in the loss of a heat sink (continued) that produces'reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated on TCV fast closure in anticipation of the transients that would result from the closure 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. For this event, the reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the EOC-RPT System, ensures that the HCPR SL is not exceeded.

Turbine Control Valve Fast Closure, Trip Oil Pressure- Low signals are initiated by the electrohydraulic control (EHC) fluid pressure at each control valve. One pressure transmitter is associated with each control valve, and the signal from each transmitter is assigned to a separate RPS logic channel. This Function must be enabled at THERMAL POWER 2 3N'TP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this function.

The Turbine Control Valve Fast Closure, Trip Oil Pressure- Low Allowable Value is selected high enough to detect imminent TCV fast closure.

Four channels of Turbine Control Valve Fast Closure, Trip Oil Pressure- Low 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. This Function is required, consistent with the analysis assumptions, whenever THERHAL POWER is 2 30K RTP. This Function is not required when THERNL POWER is ( 30% RTP, since the Reactor Vessel Steam Dome Pressure-High and the Average Power Range Nonitor Fixed Neutron Flux-High Functions are adequate to maintain the necessary safety margins.

(continued)

BFN-UNIT 2 B 3.3-18 Amendment

RPS Instrumentation B 3.3.1.1 APPLICABLE 0 e ctor Mode Switch S utdown os t SAFETY ANALYSES, LCO, and The Reactor Mode Switch -Shutdown Position Function provides APPLICABILITY signals, via the manual scram logic channels, directly to (continued) the scram pilot .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'redited 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.

The reactor mode switch is a single switch with four channels, each of which provides input into one of the RPS 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 in each trip system, are available and required to be OPERABLE. The Reactor Mode Switch -Shutdown Position Function is required to be OPERABLE in 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.

11. ua Sera The Manual Scram push button channels provide signals, via the manual 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 tri'p 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.

(continued)

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RPS Instrumentation 8 3.3.1.1 APPLICABLE ll. Manual Scram (continued)

SAFETY ANALYSES, LCO, and There is no Allowable Value for this Function since the APPLICABILITY channels are mechanically actuated based solely on the position of the push buttons.

Two channels of Manual Scram with one channel in each manual scram trip system are available and required to be OPERABLE in NODES 1 and 2, and in NODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the NODES and other specified conditions when control rods are withdrawn.

12. RPS Channel Test Switches There are four RPS Channel Test Switches, one associated with each of the four automatic scram logic channels (Al, A2, Bl, and B2). These keylock switches allow the operator to test the OPERABILITY of each individual logic channel without the necessity of using a scram function trip. When the RPS Channel Test Switch is placed in test, the associated scram logic channel is deenergized and OPERABILITY of the channel's scram contactors can be confirmed. The 'RPS Channel Test Switches are not specifically credited in the accident analysis. However, because the Manual Scram Function at Browns Ferry Nuclear Plant is not configured the same as the generic model in Reference 9, the RPS Channel Test Switches are included in the analysis in Reference 11. Reference ll concludes that the Surveillance Frequency extensions for RPS functions, described in Reference. 9, are not affected 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. Weekly testing of scram contactors is credited in Reference 9 with supporting the Surveillance Frequency extension of the RPS, functions. .

There is no Al.lowable Value for this Function since the channels are mechanically actuated solely on the position of the switches.

Four channels of the RPS Channel Test Switch Function with two channels in each trip system arranged in a one-out-of-two logic are available and required to be OPERABLE. The function is required in NODES 1 and 2, and in NODE 5 with (continued)

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RPS Instrumentation B 3.3.1.1 APPLICABLE 12. PS C a ne Test Switches (continued)

SAFETY ANALYSES, LCO, and any control rod withdrawn from a core cell containing one or APPLICABIL'ITY more fuel assemblies, since these are the NODES and other specified conditions when control rods are withdrawn.

'b

13. o Sc am lot A r Header ressur The Low Scram Pilot Air. Header Pressure trip performs the same function as the high water level in the scram discharge instrument volume for fast fill events in which the high level instrument response time may not be adequate. A fast fill event is postulated for certain degraded control air events in which the scram outlet valves unseat enough to allow 5 gpm per drive leakage into the scram discharge volume but not enough to cause rod insertion.

The Allowable Value is chosen low enough to ensure that there is sufficient volume in the SDV to accommodate the water from a full scram.

Four channels of Low Scram Pilot Air Header Pressure 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 Function is required in NODES I 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 othe'pecified conditions when control rods are withdrawn. At all other times, this Function may be bypassed.

ACTIONS A Note has been provided to modify the ACTIONS related to RPS 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 for inoperable RPS instrumentation channels provide appropriate (continued)

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RPS Instrumentation B 3.3.1.1 ACTIONS compensatory measures for separate inoperable channels. As (continued) such, a Note has been provided that allows separate Condition entry for each inoperable RPS instrumentation channel.

Because of the diversity of sensors available to provide trip signals and the redundancy of the RPS design, an allowable out of service time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> has been shown to be acceptable (Ref. 9) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function's inoperable channel is in one trip system and the Function still maintains RPS trip capability (refer to Required Actions B.l, B.2, and C.l Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel or the associated trip system must be placed in the tripped condition per Required Actions A.l 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 failure, and allow operation to continue. 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 would result in a full scram), Condition D must be entered and its Required Action taken.

~B. d 8.2 Condition B exists when, for any one or more Functions, at least one required channel is inoperable in each trip system. In this condition, provided at least one channel per trip system is OPERABLE; the RPS still maintains trip capability for that Function, but cannot accommodate a single failure in either trip system.

Required 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 arrangement for a typical four channel Function). The reduced reliability of this logic arrangement was not evaluated in Reference 9 for the 12 hour (continued)

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RPS Instr umentation B 3.3.1.1 ACTIONS ~d ( 3 dl Completion Time. Mithin the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the associated Function will have all required channels OPERABLE or in trip (or any combination) in one trip system.

Completing one of these Required Actions restores RPS to a reliability level equivalent to that evaluated in Reference 9, which justified a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowable out of service time as 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 inoperable channels are all in different Functions). The decision of which trip system is in the more degraded state should be based on prudent judgment and take into account current plant conditions (i.e., what NODE the plant is in).

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

The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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 diverse Functions, and the low probability of an event requiring the initiation of a scram.

Alternately, if 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 associated trip system in trip would result in a scram or RPT), Condition D must be entered and its Required Action taken.

Required Action C.l is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same trip system for the same Function result in the Function not maintaining RPS trip capability.

A Function is considered to be maintaining RPS trip capability when sufficient channels are OPERABLE or in trip (continued)

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RPS Instrumentation B 3.3.1.1 BASES ACTIONS ~C. (continued)

(or the associated trip system is in trip), such that both trip systems will generate a trip signal from the given Function on a valid signal.

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

Required Action D.l directs entry into the appropriate Condition referenced in Table 3.3.1.1-1. The applicable Condition specified in the Table is Function and HODE or other specified condition dependent and may change as the

,Required Action of a previous Condition is completed. Each time an inoperable channel has not met any Required Action of Condition A, B, or C and the associated Completion Time has expired, Condition D will be entered for that channel and provides for transfer to the appropriate subsequent Condition.

E.l .1 and G. 1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a NODE or other specified condition in which the LCO does not apply. The allowed Completion Times are reasonable, based on operating experience, to reach the specified condition from full power conditions in an orderly manner and without challenging plant systems. In addit'i'on, the Completion Time of Required Action E.l is consistent with the Completion Time provided in LCO 3.2.2, "HINIHUH CRITICAL POWER RATIO (HCPR);."

If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in (continued)

BFN-UNIT 2 B 3.3-24 Amendment

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RPS Instrumentation B 3.3.1.1 BASES ACTIONS g,l (continued) trip) within the allowed Completion Time, the plant must be placed in a NODE or other specified condition in which the LCO does not apply. This is done by immediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core 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.

SURVEILLANCE 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 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 RPS trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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. 3) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not significantly reduce the probability that the RPS will trip when necessary.

SR 3.3 1.1.

Performance of the CHANNEL CHECK once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 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 indication of excessive instrument drift in one of the channels or (continued)

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RPS Instrumentation B 3.3.1.1 SURVEILLANCE SR 3.3.1.1.1 (continued)

RE(UIREMENTS 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.

The Frequency is based upon operating experience that demonstrates channel failure is rare. 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 average power, the APRMs are calibrated to the reactor power .calculated from a heat balance. LCO 3.2.4, "Average Power Range Monitor (APRM) Gain and Setpoints," allows the APRMs to be reading greater, than actual THERMAL POWER to compensate for localized power peaking. When this adjustment is made, the requirement for the APRMs to indicate within 2% RTP of calculated power is modified. to require the APRMs to indicate within 2% RTP of calculated MFLPD. The Frequency of once per 7 days is based on minor changes in LPRM sensitivity, which could affect the APRM reading, between performances of SR 3.'3. 1. 1.7.

A restriction to satisfying this SR when < 25% RTP is provided that requires the SR to be met only at a .25% RTP because it is diffi'cult to accurately maintain APRM indication of core THERMAL POWER consistent with, a heat balance when < 25% RTP. At low power levels, a high degree of accuracy is unnecessary because of the large, inherent margin to thermal limits (MCPR and APLHGR). At ~ 25% RTP, the Surveillance is required to have been satisfactorily performed within the last 7 days, in accordance with SR 3.0.2. A Note is provided, which allows an increase in THERMAL POWER above 25% if the 7 day Frequency is not met (continued)

BFN-UNIT 2 B 3.3'-26 Amendment

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RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3. 1. 1.2 (continued)

RE(UIREMENTS per SR 3.0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reaching or exceeding 25% RTP. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

SR 3.3.1.1.3 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 the assumptions of the current plant specific setpoint methodology.

As noted, SR 3.3.1. 1.3 is not required to be performed when entering MODE 2 from MODE 1, since testing of the MODE 2 required IRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This allows entry. into MODE 2 if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE 2 from MODE 1. Twelve hours is based on operating experience and: in consideration of providing a reasonable time in which to complete the SR.

A Frequency of 7 days provides an acceptable level of system average unavailability over the Frequency interval and is based on reliability analysis (Ref. 9).

SR 3.3.1.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel wi.l.l perform. the intended function. A Frequency of 7 days provides an acceptable level of system average availability over the Frequency and is based on the reliability analysis of Reference 9. (The RPS Channel Test Switch Function's CHANNEL FUNCTIONAL TEST Frequency was credited in the analysis to extend many automatic scram Functions'requencies.)

0 (continued)

BFN-UNIT 2 B 3.3-27 Amendment

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RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE S 3.3 and S 3 3 1 6 REQUIREMENTS (continued) These Surveillances are established to ensure that no gaps in neutron flux indication exist from subcritical to power operation for monitoring core reactivity status.

The overlap between SRMs and IRMs is required to be demonstrated to ensure that reactor power will not be increased into a neutron flux region without adequate indication. This is required prior to withdrawing SRMs from the fully inserted position since indication is being transitioned from the SRMs to the IRMs.

The overlap between IRHs and APRMs is of concern when reducing power into the IRM range. On power increases, the system design will prevent further increases (by initiating a rod block)

.between if adequate overlap is not maintained. Overlap IRMs and APRHs exists when sufficient IRMs and APRMs concurrently have onscale readings such that the transition between MODE 1 and MODE 2 can be made without either APRH downscale rod block, or IRH upscale rod block. Overlap between SRHs and IRHs similarly exists when, prior to withdrawing the SRHs from .the fully inserted position, IRHs are above mid-seal'e on range 1 before SRHs have reached the upscale rod block.

As noted, SR 3.3.1.1.6 is only required to be met during entry into NODE 2 from MODE 1. That is, after the overlap requirement has been met and indication has transitioned to the IRHs, maintaining overlap is not required (APRMs may be reading downscale once in MODE 2).

If overlap for a group of channels is not demonstrated (e.g., IRH/APRH overlap), the reason for the failure of the Surveillance should be determined and the appropriate channel(s) declared inoperable. Only those appropriate channels that are required in the current NODE or condition should be declared inoperable.

A Frequency of 7 days is reasonable based on engineering judgment and the reliability .of the IRMs and APRHs.

(continued)

C BFN-UNIT 2 B 3.3-28 Amendment

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RPS Instrumentation 8 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.7 REQUIREMENTS (continued) LPRH gain settings are determined from the local flux profiles measured by the Traversing Incore Probe (TIP)

System. This establishes the relative local flux profile for appropriate representative input to the APRM System.

The 1000 effective Full power hours Frequency is based on operating experience with LPRH sensitivity changes.

SR 3.3.1.1.8 SR 3.3.1.1.12 and SR 3.3.1.1.16 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 the assumptions of the current plant specific setpoint .methodology. The 92 day Frequency of SR 3.3. 1. 1.8 is based on the rel.iability analysis of Reference 9.

The 184 day Frequency of SR 3.3. 1. 1.16 for the scram pilot air header 1'ow pressure trip function is based on the functional reliability previously demonstrated by this function, the need for minimizing the radiation exposure associated with the functional testing of this function, and the increased risk to plant availability while the plant is in a half-scram condition during the performance of the functional testing versus the limited increase in reliability that would be obtained by the more frequent functional testing.

The 18 month Frequency of SR 3.3. 1. 1. 12 is based on the need to perform this Surveillance under the conditions that apply during a. plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency.

SR 3.3.1.1.9 SR 3.3.1.1.10 and SR 3.3.1.1.13 A CHANNEL CALIBRATION is 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 (continued)

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RPS Instrumentation B 3.3.1.1 SURVEILLANCE SR 3.3. 1. 1.9 SR 3.3. 1. 1.10 and SR 3.3. 1. 1. 13 (continued)

REgUIREHENTS adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. For the APRH Simulated Thermal Power-High Function, SR 3.3.1.1.9 also includes calibrating the associated recirculation loop flow channel. For HSIV-Closure, SDV Water Level-High (Float Switch), and TSV-Closure Functions, SR 3.3.1.1.13 also includes physical inspection and actuation of the switches.

Note 1 to SR 3.3.1.1.9 states that neutron detectors are excluded from CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Changes in neutron detector sensitivity are compensated for by performing the 7 day calorimetric calibration (SR 3.3.1. 1.2) and the 1000 effective full power hours LPRH calibration against the TIPs (SR 3.3.1.1.7). A second Note for SR 3.3.1.1.9 is provided that requires the APRH and IRH SRs to be performed within 12 hours of entering HODE 2 from HODE 1. Testing of the NODE 2 APRH and IRH Functions cannot be performed in HODE 1 without utilizing jumpers, lifted leads, or movable 1;inks. This Note allows entry into NODE 2 from NODE 1 if the associated'requency is not met per SR 3.0.2. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

'he Frequency of SR 3.3.1. 1.9 is based upon the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3. 1. 1. 10 is based upon the assumption of a 184 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.1. 1.13 is based upon the assumption of an 18 month calibration interval in the determination of the magnitude of .equipment drift in the setpoint analysis.

SR 3.3.1.1'.11 The Average Power Range Honitor Flow Biased Simulated Thermal Power- High Function uses the recirculation loop drive flows to vary the trip setpoint. This SR ensures that the total loop drive flow signals from the flow units used to vary the setpoint are appropriately compared to a (continued)

BFN-UNIT 2 B 3.3-30 Amendment

0 RPS Instrumentation B 3.3.1.1 SURVEILLANCE SR 3.3.1.1.11 (continued)

RE(UIR EVENTS The Frequency of,18 months is based on system design considerations which do not support flow unit bypass during operation. Thus, this calibration is performed during refueling outages.

SR 3.3.1.1.14 The LOGIC SYSTEM FUNCTIONAL TEST .demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods (LCO 3.1.3), and SDV vent and drain valves (LCO 3.1.8),

overlaps this Surveillance to provide complete testing of the assumed safety function.

The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

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

SR 3.3.1.1.15 This SR ensures that scrams initiated from the Turbine Stop Valve Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure Low Functions will not be inadvertently bypassed. when THERMAL POWER is ) 30% RTP. This involves margins for calibration of the bypass channels. Adequate the instrument setpoint methodologies are incorporated into the actual setpoint.

If any bypass channel's setpoint is nonconservative (i.e.,

the Functions are bypassed at a 30% 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 condition (Turbine Stop Valve .Closure and Turbine Control Valve Fast Closure, Trip (continued)

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RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.'15 (continued)

REQUIREMENTS.

Oil Pressure Low Functions are enabled), .this SR is met and the channel is considered OPERABLE.

The Frequency of 18 months, is, based on engineering judgment and reliability of. the components.

REFERENCES 1. FSAR, Section'..2.

2. FSAR, Chapter 14.

3. NED0-23842, "Continuous Control Rod Withdrawal in the Startup Range," April 18, 1978.

4. .FSAR, Appendix N.

5. FSAR, Section )4.6.2.

6. FSAR, Section 6.5.

7. FSAR, Section 14.5.

8. P. Check (NRC) letter to,G..Lainas (NRC),, "BWR Scram Discharge System Safety Evaluation," December '1, 1980.

9. NEDC-30851-P-A , "Technical Specification Improvement Analyses for,BHR Reactor Protection System,"

March 1988.

.10. NRC No.93-102, "Final Policy Statement:on Technical Specification Improvements," July '23, 1993.

11. NED-32-0286, "Technical Specification Improvement Analysis for Browns. Ferry Nuclear Plant, Unit 2,"

October 1995.

BFN-UNIT '2 B 3.3-32 Amendment

il SRH Instrumentation B 3.3.1.2 B 3.3 INSTRUMENTATION B 3.3.1.2 Source Range Monitor (SRH) Instrumentation BASES BACKGROUND The SRHs provide the operator with information relative to the neutron flux level at very low flux levels in the core.

As such, the SRH indication is used by the operator to monitor the approach to criticality and determine when criticality is achieved. The SRHs are maintained fully inserted until the count rate is greater than a minimum allowed count rate (a control rod block is set at this condition). After SRH to intermediate range monitor (IRM) overlap is demonstrated (as required by SR 3.3. 1.1.5), the SRMs are normally fully withdrawn from the core.

The SRM subsystem of the Neutron Monitoring System (NHS), as described in Reference 1, consists of four channels. Each of the SRM channels can be bypassed, but only one at any given time, by the operation of a bypass switch. Each channel includes one detector that can be physically positioned in the core. Each detector assembly consists of a miniature fission chamber with associated cabling, signal conditioning equipment, and electronics associated with the various SRH functions. The signal conditioning equipment converts 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 SRHs.

During refueling, shutdown, and low power operations, the primary indication of neutron flux levels is provided by the SRMs or special movable detectors connected to the normal SRH circuits. The SRHs provide monitoring of reactivity changes during fuel or control rod movement and give the control room operator early indication of subcritical multiplication that could be indicative of an approach to criticality.

APPLICABLE Prevention and mitigation of prompt reactivity excursions SAFETY ANALYSES during refueling and low power operation is provided by LCO 3.9. l, "Refueling Equipment Interlocks"; LCO 3.1.1, (continued)

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SRM Instrumentation B 3.3.1.2 BASES APPLICABLE "SHUTDOWN MARGIN (SDM)"; LCO 3.3. 1.1, "Reactor Protection SAFETY ANALYSES System (RPS) Instrumentation"; IRM Neutron Flux-High and (continued) Average Power Range Monitor (APRM) Neutron Flux-High, Setdown Functions; and LCO 3.3.:2. 1, "Control Rod Block Instrumentation."

The SRMs have no safety function and, are not assumed to function during any FSAR design basis accident or transient analysis. However, the SRMs provide the only on scale monitoring of neutron flux levels during startup and refueling. Therefore, they are being retained in Technical Specifications.

LCO During startup in MODE 2, three of the four SRM channels are required to be OPERABLE to monitor the reactor flux level prior to and during control rod withdrawal, subcritical multiplication and reactor criticality, and neutron flux level and reactor period until the flux level is sufficient to maintain the IRMs on Range 3 or above. All but one of the channels are required 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 SRM channels provide redundant monitoring of flux levels in the core.

In MODE 5, during a spiral offload or reload, an SRM 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. Thus, CORE ALTERATIONS are allowed in a quadrant with no OPERABLE SRM in an adjacent quadrant provided the Table 3.3. 1.2-1, footnote (b),

requirement that the bundles being spiral reloaded or spiral offloaded are all in a single fueTed region containing at least one OPERABLE SRM 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 operations, two SRMs are required to be OPERABLE to provide redundant monitoring of reactivity (continued)

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SRM Instrumentation B 3.3.1.2 LCO changes occurring in the reactor core. Because of the local (continued) nature of reactivity changes during refueling, adequate coverage is provided by requiring one SRM to be OPERABLE in the quadrant of the reactor core where CORE ALTERATIONS are being performed, and the other SRH to be OPERABLE in an adjacent quadrant containing fuel. These requirements ensure that the reactivity of the core will be continuously monitored during CORE ALTERATIONS.

Special movable detectors, according to footnote (c) of Table 3.3.1.2-1, may be used in place of the normal SRH nuclear detectors. These special detectors must be connected to the normal SRH circuits in the NMS, such that the applicable neutron flux indication can be generated.

These special detectors provide more flexibility 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 SRMs.

For an SRH channel to be considered OPERABLE, it must be providing neutron flux monitoring indication.

APPLICABILITY The SRMs are required to be OPERABLE in MODES 2, 3, 4, and 5 prior to the IRMs being on scale on Range 3 to provide for neutron monitoring. In MODE 1, the APRHs provide adequate monitoring of reactivity changes in the core; therefore, the SRMs are not required. In MODE 2, with IRMs on Range 3 or above, the IRHs provide adequate monitoring and the SRHs are not required.

ACTIONS A.l and B.l In MODE 2, with the IRMs on Range 2 or below, SRMs provide the means of monitoring core reactivity and criticality.

With any number of the required SRHs inoperable, the ability to monitor neutron flux is degraded. Therefore, a limited time is allowed to restore the inoperable channels to OPERABLE status.

(continued)

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SRM Instrumentation B 3.3.1.2 ACTIONS A.l and B. 1 (continued)

Provided at least one SRH remains OPERABLE, Required Action A. 1 allows 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to restore the required SRHs to OPERABLE status. This time is reasonable because there is adequate capability remaining to monitor the core, there is limited risk of an event during this time, and there is sufficient time to take corrective actions to restore the required SRMs to OPERABLE status or to establish alternate IRM monitoring capability. During this time, control rod withdrawal and power increase is not precluded by this Required Action. Having the ability to monitor the core with at least one SRH, proceeding to IRH Range 3 or greater (with overlap required by SR 3.3.1.1.5), and thereby exiting the Applicability of this LCO, is acceptable for ensuring adequate core monitoring and allowing continued operation.

With three required SRMs inoperable, Required Action B.l allows no positive changes in reactivity (control rod withdrawal must be immediately suspended) due to inability to monitor the changes. Required Action A.l still applies and allows 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 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 immediately shut down, with no SRMs OPERABLE.

C.1 In MODE 2, if thewithin required the number of SRHs is not restored to allowed Completion Time, the OPERABLE status reactor shall be placed in MODE 3. With all control rods fully inserted, the core is in its least reactive state with the most margin to criticality. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 in an orderly manner and without challenging plant systems.

D. 1 and D.2 With one or more required SRMs inoperable in MODE 3 or 4, the neutron flux monitoring capability is degraded or nonexistent. The requirement to fully insert all insertable (continued)

BFN-UNIT 2 B 3.3-36 Amendment

ili SRM Instrumentation B 3.3.1.2 BASES ACTIONS D. 1 and 0.2 (continued) control rods ensures that the reactor will be at its minimum reactivity level while no neutron monitoring capability is available. Placing the reactor mode switch in the shutdown position prevents subsequent control rod withdrawal by maintaining a control rod block. The allowed Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is sufficient to accomplish the Required Action, and takes into account the low probability of an event requiring the SRM occurring during this interval.

E.l and E.2 With one or more required SRM inoperable in MODE 5, the ability to detect local reactivity changes in the core during refueling is degraded. CORE ALTERATIONS must be immediately suspended and action must be immediately initiated to insert all insertable control rods in core cells containing one or more fuel assemblies. 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 will 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.'ction (once required to be initiated) to insert control rods must continue until all i'nsertable rods in core cells containing one or more fuel assemblies are inserted.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each SRM RE(UIREMENTS Applicable MODE or other specified conditions are found in the SRs column of Table 3.3. 1.2-1.

SR 3.3.1.2.1 and SR 3.3.1.2.3 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 another channel. It is based on the assumption that instrument channels (continued)

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SRH Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3.1.2.1 and SR 3.3.1.2.3 (continued)

RE(U IREHENTS 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. it A CHANNEL CHECK will detect gross channel failure; thus, 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.

The Frequency of once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for SR 3.3.1.2.1 is based on operating experience that demonstrates channel failure is rare. While in HODES 3 and 4, reactivity changes are not expected; therefore, the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is relaxed to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for SR 3.3.1.2.3. 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, when the fueled region encompasses more than one SRH, one SRH .is required to be OPERABLE in the quadrant where CORE ALTERATIONS are being performed, and the other OPERABLE SRH must be in an adjacent quadrant containing fuel. Note 1 states that the SR is required to be met only during CORE ALTERATIONS. It is riot required to be met at other times in NODE 5 since core reactivity changes are not occurring. This Surveillance consists of a review of plant logs to ensure that SRHs required to be OPERABLE for given CORE ALTERATIONS are, in fact, OPERABLE. In the event that only one SRH is required to be OPERABLE (when the fueled region encompasses only one SRH), per Table 3.3.1.2-1, footnote (b), only the a. portion. of this SR is required.

Note 2 clarifies that more than one of the three requirements can be met by the same OPERABLE SRH. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is based upon operating experience and supplements operational controls over refueling activities (continued)

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SRM Instrumentation B 3.3.1.2 SURVEILLANCE SR 3.3.1.2.2 (continued)

REQUIREMENTS that include steps to ensure that the SRMs required by the LCO are in the proper quadrant.

SR 3.3.1.2.4 This Surveillance consists of a verification of the SRM instrument readout to ensure that the SRM 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. With few fuel assemblies loaded, the SRMs will not have a high enough count rate to satisfy the SR. Therefore, allowances are made for loading sufficient "source" material, in the form of irradiated fuel assemblies, to establish the minimum count rate.

To accomplish this, the SR is modified by Note 1 that states that the count rate is not required to be met on an SRM that has less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies are in the associated core quadrant. With four or less fuel assemblies loaded around each SRM 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 not 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 Frequency is based upon channel redundancy and other information available in the control room, and ensures that the required channels are frequently monitored whi.le core reactivity changes are occurring. When no reactivity changes are in progress, the Frequency is relaxed from 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

SR 3.3.1.2.5 and SR 3.3.1.2.6 Performance of a CHANNEL FUNCTIONAL TEST demonstrates the associated channel will function properly. SR 3.3.1.2.5 is required in MODE 5, and the 7 day Frequency ensures that the channels are OPERABLE whi.le core reactivity changes could be in progress. This Frequency is reasonable, based on (continued)

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SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE SR 3.3. 1.2.5 and SR 3.3.1.2.6 (continued)

REQUIREMENTS operating experience and on other Surveillances (such as a CHANNEL CHECK), that ensure proper functioning between CHANNEL FUNCTIONAL TESTS.

SR 3.3.1.2.6 is required in MODE 2 with IRMs on Range 2 or below, and in MODES 3 and 4. Since core reactivity changes do not normally take place in MODES 3 and 4 and core reactivity changes are due only to control rod movement in MODE 2, the Frequency has been extended from 7 days to 31 days. The 31 day Frequency is based on operating experience and on other Surveillances (such as CHANNEL CHECK) that ensure proper functioning between CHANNEL FUNCTIONAL TESTS.

Verification of the signal to noise ratio also ensures that the detectors are inserted to an acceptable operating level.

In a fully withdrawn condition, the detectors are sufficiently removed from the fueled region of the core to essentially eliminate neutrons from reaching the detector.

Any count rate obtained while the detectors are fully withdrawn is assumed to be "noise" only.

The Note to the Surveillance allows the Surveillance to be delayed, until entry into the specified condition of the Applicability (THERMAL POWER decreased to IRM Range 2 or below). The SR must be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after IRMs are on Range 2 or below. The allowance to enter the Applicability with the 31 day Frequency not met is reasonable, based on the limited time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed after entering the Applicability and the inability to perform the Surveillance while at higher power levels.

Although the Surveillance could be performed while on IRM Range 3, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances.

SR 3.3.1.2.7 Performance of a CHANNEL CALIBRATION at a Frequency of 92 days verifies the performance of the SRM detectors and (continued)

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SRM Instrumentation B 3.3.1.2 SURVEILLANCE SR 3.3.1.2.7 RE(UIREMENTS (continued)'ssociated circuitry. The Frequency considers the plant conditions required to perform the test, the ease of performing the test, and the likelihood of a change in the system or component status. The neutron detectors are excluded from the CHANNEL,CALIBRATION (Note 1) because they cannot readily be adjusted. The detectors are fission chambers that are des'igned to have a relatively constant sensiti.vity over the range and with an accuracy specified for a fixed useful life.

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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of entering MODE 2 with IRMs on Range 2 or below. The al.lowance to enter the Applicability with the 18 month Frequency .not met is reasonable, based on the limited time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowed after entering the Applicability and the inability to perform the Surveillance while at higher power levels. Although 'the Surveillance could be performed while on IRM Range', the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 'Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to

.perform the Surveillances.

REFERENCES 1. FSAR, Section 7.5.4.

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Control Rod Block Instrumentation B 3.3.2.1 B 3.3 INSTRUMENTATION B 3.3.2.1 Control Rod Block Instrumentation BASES 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 transients and accidents. During high power operation, the rod block monitor (RBM) provides protection for control rod withdrawal error events.'uring 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 Function ensure that all control rods remain inserted to prevent inadvertent criticalities.

The purpose of the RBM is to limit control rod withdrawal if local. ized neutron flux exceeds a predetermined setpoint during control rod manipulations. It is assumed to function to block further control rod withdrawal to preclude a MCPR Safety Limit (SL) violation. The RBM supplies a trip signal to the Reactor Manual Control System (RHCS) to appropriately inhibit control rod withdrawal during power oper ation above the low power range setpoint. The RBM has two channels, either of which can initiate a control rod 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 core heights surrounding the control rod being withdrawn. A signal from one average power range monitor (APRM) channel assigned to each Reactor Protection System (RPS) trip system supplies a reference signal for the RBM channel in the same trip system. If the APRM is indicating less than the low power setpoint, the RBM is automatically bypassed. The RBM is also automatically bypassed if a peripheral control rod is selected (Ref. 1).

(continued)

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Control Rod Block Instrumentation B 3.3.2.1 BASES BACKGROUND The purpose of the RWM is to control rod patterns during (continued) startup and'hutdown, such that only specified control rod sequences and relative positions are allowed over the operating range from all control rods inserted to lOX RTP.

The sequences effectively limit the potential amount and rate of reactivity increase during a CRDA. Prescribed control rod sequences are stored in the RWM, which will initiate control rod withdrawal and insert blocks when the actual sequence deviates beyond allowances 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 signals to determine when the reactor power is above the preset power level at which the RWM is 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 is applied to all control rods to ensure that the shutdown condition is maintained. This 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 in the shutdown position. The reactor mode switch. has two channels, each inputting into a separate RHCS rod block circuit. A. rod block in either RMCS circuit will provide a control rod,block to all control, rods.

APPLICABLE l. od Block Monitor SAFETY. ANALYSES, LCO, and The RBH is designed to prevent violation of the HCPR APPLICABILITY SL and the cladding lh plastic strain fuel design limit that may result from a single control rod withdrawal error (RWE) event. The analytical methods and assumptions used in evaluating the RWE event are summarized in Reference 3. A statisti'cal analysis of RWE events was performed to determine the RBH response for both channels for each event.

From these responses, the fuel thermal 'performance as a function of RBM Allowable Value was determined. Note that the RBH setpoint is flow-biased until implementation of ARTS improvements described in Reference 3. However, the generic RWE analysis in Reference 3 is currently applicable to establish required conditions for RBM OPERABILITY..

(continued)

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Control Rod Block Instrumentation B 3.3.2.1 APPLICABLE d lock o tor (continued)

SAFETY ANALYSES, LCO, and The RBH Function satisfies Criterion 3 of the NRC Policy APPLICABILITY Statement (Ref. 10).

Two channels .of the RBH are required to be OPERABLE, with their setpoints within the appropriate Allowable Value to ensure that no single instrument failure can preclude a rod from this Function. The setpoints are calibrated 'lock consistent with applicable setpoint methodology (nominal trip setpoint).

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

Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor power), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g.,

trip unit) changes state. The analytic limits are derived from the limiting values of the process parameters .obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument error s (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration toler ances, instrument drift, and severe environmental effects (for channels that must function in, harsh environments as defined by 10 CFR 50.49) are accounted for.

The RBH is assumed to mitigate the consequences of an RWE event when operating > 2%'TP. Below this power level, the consequences of an RWE event will not exceed the HCPR SL and, therefore, the RBH is not required to be OPERABLE (Ref. 3). When operating < 9N RTP, analyses (Ref. 3) have shown that with an initial HCPR h 1.70, no RWE event will result in exceeding the HCPR SL. Also, the analyses demonstrate that when operating at > 9'TP with HCPR > 1.40, no RWE event will result in exceeding the HCPR (continued)

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Control Rod Block Instrumentation B 3.3.2.1 APPLICABLE 1 od 8 ock onitor (continued)

SAFETY ANALYSES, LCO, and SL (Ref. 3). Therefore, under these conditions, the RBH is APPLICABILITY also not required to be OPERABLE.

2. od Wo th inimize The RWM enforces the banked position withdrawal sequence (BPWS) 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 4, 5, 6, and 7. The BPWS requires that control rods be moved in groups, with all 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 BPWS are specified in LCO 3.1.6, "Rod Pattern Control."

The RWM Function satisfies Criterion 3 of the NRC Policy Statement (Ref. 10).

Since the RWM is 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. 7). Special circumstances provided 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 BPWS. The RWM may be bypassed as .required by these conditions, but then it must be considered inoperable and the Required Actions of this LCO followed.

Compliance with the BPWS, and therefore OPERABILITY of the RWM, is required in MODES 1 and 2 when THERMAL POWER is

( 10% RTP. When THERMAL POWER is > I'll 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. 5 and 7). 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 SDH ensures that the consequences of a CRDA are acceptable, since the reactor will be subcritical.

(continued)

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Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE 3. e ctor Mode Sw t Shutdow Posit'on SAFETY ANALYSES, LCO, and During MODES 3 and 4, and during MODE 5 when the reactor APPLICABILITY mode switch is required to be in the shutdown position, the (continued) core is assumed to be subcritical; therefore, no positive reactivity insertion events are analyzed. The Reactor Mode Switch-Shutdown Position control rod withdrawal block ensures that the reactor remains subcritical by blocking control rod withdrawal, thereby preserving the assumptions of the safety analysis.

The Reactor Mode Switch -Shutdown Position Function satisfies Criterion 3 of the NRC Policy Statement (Ref. 10).

Two channels are required to be OPERABLE to ensure that no single channel failure will preclude a rod block when required. There is no Allowable Value for this 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 refueling position, the refuel position one-rod-out interlock (LCO 3.9.2, "Refuel Position One-Rod-Out Interlock" ) provides the required control rod withdrawal blocks.

With one RBM channel inoperable, the remaining OPERABLE channel is adequate to perform the control rod block function; however, overall reliability is reduced because a single failure in the remaining OPERABLE channel can result in no control rod block capability for the RBM. For this reason, Required Action A. 1 requires restoration of the inoperable channel to OPERABLE status. The Completion Time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is based on the low probability of an event occurring coincident with a failure in the remaining OPERABLE channel.

(continued)

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0 Control Rod Block Instrumentation B 3.3;2.1 ACTIONS (continued)

If Required Action A.l is not met and the associated Completion Time has expired, the inoperable channel must be placed in trip within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. If both RBM channels are inoperable, the RBM is not capable of performing its intended function; thus, one channel must also be. placed in trip. This initiates a control rod withdrawal block, thereby ensuring that the RBM function is met.

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

C.l C. .1 C. . .2 a d C.2.

With the RWM inoperable during a reactor startup, the operator is still capable of enforcing the prescribed control rod sequence. However, the overall reliability is reduced because a single operator error can 'result in violating the control rod sequence. 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 during withdrawal of one or more of the first 12 rods 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 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 manually and requires a double check of compliance with the prescribed rod sequence by a second licensed operator (Reactor Operator or Senior Reactor Operator) or other qualified member of the technical staff (e.g., a qualified shift technical advisor or reactor engineer).

(continued)

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Control Rod Block Instrumentation B 3.3.2.1 BASES ACTIONS C .2 C 1. d C.2. (continued)

The RWM may be bypassed under these conditions to allow continued operations. In addition, Required Actions of LCO 3. 1.3 and LCO 3.1.6 may require bypassing the RWM, during which time the RWM must be considered inoperable with Condition C entered and its Required Actions taken.

With the RWM inoperable during a reactor shutdown, the operator is still capable of enforcing the prescribed control rod sequence. Required Action 0.1 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 Operator) or other qualified member of the technical staff.

The RWM may be bypassed under these conditions to allow the reactor shutdown to continue.

.1 nd With one Reactor Mode Switch -Shutdown Position control rod withdrawal block channel inoperable, the remaining OPERABLE channel is adequate to perform 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 all insertable control rods in core cells containing one or more fuel assemblies will ensure that the core is subcritical with adequate SDM ensured by LCO 3.1.1. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core 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.

(continued)

BFN-UNIT 2 B 3.3-48 Amendment

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Control Rod Block Instrumentation B 3.3.2.1 SURVEILLANCE As noted at the beginning of the SRs, the SRs for each RE(UIREMENTS Control Rod Block instrumentation Function are found in the SRs column of Table 3.3.2. 1-1.

The Surveillances are modified by a second Note (Note 2) 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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains control rod block capability. Upon completion of the Surveill'ance, or expiration. of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> al,lowance, 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. 9) assumption of the average time required to perform a channel.

Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not significantly reduce the probability that a control rod block will be initiated when necessary.

SR 3.3.2.1.1 A CHANNEL -FUNCTIONAL TEST is performed for each RBM channel to ensure that the entire channel will per'form the intended function. It includes the Reactor Manual Control System input.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Frequency. of 92 days is based on reliability analyses (Ref. 8).

SR 3.3.2.1.2 and SR 3.3.2.1.3 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 attempting to withdraw a control rod not in compliance with the prescribed sequence and verifying a control rod block occurs. This test is performed as soon as possible after the applicable conditions are entered. As noted in the SRs, SR 3.3.2. 1.2 is not required to be. performed until 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after any control rod is withdrawn at a 10% RTP in MODE 2.

As noted, SR 3.3.2.1.3 is not required to be performed until (continued)

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Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE SR 3.3.2. 1.2 and SR 3.3.2. 1.3 (continued)

REQUIREMENTS 1 hour after THERMAL POWER is reduced to a 10% RTP in MODE 1. This allows entry into MODE 2 for SR 3.3.2.1.2, and THERMAL POWER reduction to a 10% RTP for SR 3.3.2.1.3, to perform the required Surveillance if the 92 day Frequency is not met per SR 3.0.2. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs. The Frequencies are based on reliability analysis (Ref. 8).

SR 3.3.2.1.4 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. CHANNEL CALIBRATION 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 3.3.1.1.7.

The Frequency is based upon the assumption of a 184 day calibration interval in, the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.2.1.5 The RWM is automatically bypassed when power is above a specified value. The power level is determined from feedwater flow and steam flow signals. The automatic bypass setpoint must be verified periodically to be ) 10% RTP. If the RWM low power setpoint is nonconservative, then the RWN is considered inoperable. Alternately, the low power setpoint channel can be placed. in the conservative condition (nonbypass). If placed in the nonbypassed condition, the SR is met and the RWM is not considered inoperable. The Frequency is based on the trip setpoint methodology utilized for the low power setpoint- channel.

(continued)

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Control Rod Block Instrumentation B 3.3.2.1 SURVEILLANCE S 3.3.2.

REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode

Switch Shutdown Position Function to ensure that the entire channel will perform the intended function. The CHANNEL FUNCTIONAL TEST for the Reactor Mode Switch -Shutdown Position Function is performed by attempting 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 Surveillance is not required to be performed until 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 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 NODES 3 and 4 if the 18 month Frequency is not. met per SR 3.0.2. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs.

The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant

.outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

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

SR 3 3.2.1 7.

The RWM will only enforce 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 into the RWM so that it can perform 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. FSAR, Section 7.5.8.2.3.

2. FSAR, Section 7.16.5.3.1.k.

(continued)

BFN-UNIT 2 B 3.3-51 Amendment

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Control Rod Block Instrumentation B 3.3.2.1 BASES REFERENCES 3. NEDC-32433P, "Haximum Extended Load Line Limit and (continued) ARTS Improvement Program Analyses for Browns Ferry Nuclear Plant Unit 1, 2 and 3," April 1995.

4. NEDE-24011-P-A-US, "General Electrical for Reload Fuel," Supplement Standard'pplication for United States, (revision specified in the COLR).

5. "Modifications to the Requirements for Control Rod Drop Accident Mitigating Systems," BMR Owners'Group, July 1986.

6. NEDO-21231', "Banked Position Withdrawal Sequence,"

January 1977.

7. NRC'ER, "Acceptance of Referencing, of Licensing Topical Report NEDE-24011-P-A," "General Electric Standard Application for Reactor Fuel, Revision 8, Amendment 17," December 27., 1987.

8. NEDC-30851-P-A, Supplement 1, "Technical Specification Improvement Analysis for BWR Control Rod Block

'nstrumentation," October 1988.

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

10. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

BFN-UNIT 2 B 3.3-52 Amendment

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Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 B 3.3 INSTRUMENTATION B 3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation BASES BACKGROUND The feedwater and main turbine high water level trip instrumentation is designed to detect a potential failure of the Feedwater Level Control System that causes excessive feedwater flow.

With excessive feedwater flow, the water level'n the reactor vessel ri'ses toward the high water level reference point, causing the trip of the three feedwater pump turbines and the main turbine.

Reactor Vessel Water Level High signals are provided by level sensors 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 in the reactor vessel (variable leg). Two channels of Reactor Vessel Water Level High instrumentation per trip system are provided as input to a two-out-of-two initiation logic that trips the three feedwater pump turbines 'and the main turbine. There are two trip systems, either of which will initiate a trip.

The channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a main feedwater and turbine trip signal to the trip logic.

A trip of the feedwater pump turbines limits further increase in reactor vessel water level by limiting 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.

APPLICABLE The feedwater and main turbine high water level trip SAFETY ANALYSES instrumentation is assumed to be capable of, providing a turbine trip in the design basis transient analysis for a feedwater controller failure, maximum demand event (Ref. I).

The reactor vessel high water level trip indirectly initiates a reactor, scram from the main turbine trip (above 30% RTP) and trips the feedwater pumps, thereby terminating (continued)

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Feedwater and Hain Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES APPLICABLE the event. The reactor scram mitigates the reduction in SAFETY ANALYSES HCPR.

(continued)

Feedwater and main turbine high water level trip instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 3).

LCO The LCO requires two channels of the Reactor Vessel Water Level High instrumentation per trip system to be OPERABLE to ensure that no single instrument failure will prevent the feedwater pump turbines and main turbine trip on a valid Reactor Vessel Water Level High, signal. Both channels in either trip system are needed to provide trip signals in order for the feedwater and main turbine trips to occur.

Each channel must have its setpoint set within the specified Allowable Value of SR 3.3.2.2.3. 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 assumptions. 'ominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between successive, CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel 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 limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, (continued)

BFN-UNIT 2 B 3.3-54 Amendment

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Feedwater and Hain Turbine High Mater Level Trip Instrumentation B 3.3.2.2 BASES LCO instrument drift, and severe environmental effects (for (continued) channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.

APPLICABILITY The feedwater and main turbine high water level trip instrumentation is required to 'be OPERABLE at a 25% RTP to ensure that the fuel cladding integrity Safety Limit and the cladding 1% plastic strain, limit are not violated during the feedwater controller failure, maximum demand event. As discussed in the Bases for LCO 3.2.1, "Average Planar Linear Heat Generation Rate (APLHGR)," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (HCPR)," sufficient margin to these limi.ts exists below 25% 'RTP; therefore, these requirements are only necessary when operating at or above this power level.

A Note.has been provided to modify the ACTIONS related to feedwater and main turbine 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 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 feedwater 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 turbine high water level trip instrumentation channel.

A.

1'ith

• one channel inoperable in one trip system, the remaining two OPERABLE channels in the other trip system can provide the required trip signal. However, overall instrumentation reliability is reduced because a single failure in one of the two channels of that trip system (continued)

BFN-UNIT 2 B 3.3-55 Amendment

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Feedwater and Hain Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES ACTIONS A. l (continued) concurrent with feedwater controller failure, maximum demand event, may result in the instrumentation not being able to perform its intended function. Therefore, continued operation is only allowed for a limited time with one channel inoperable. If the inoperable channel cannot be restored to OPERABLE status within the Completion Time, the channel must be placed in the tripped condition per Required Action A. l. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single 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 a feedwater or main turbine trip), Condition C must be entered and its Required Action taken.

The Completion Time of 7 days is based on the low probability of the event occurring coincident with a single failure in a'remaining OPERABLE channel.

B.l With one or more channels inoperable in each trip system, the feedwater and main turbine high water level trip instrumentation cannot perform its design function (feedwater and main turbine high water level trip capability is not maintained). Therefore, continued operation is only permitted for a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> period, during which feedwater and main turbine high water level trip capability must be restored. The .trip capability is considered maintained when sufficient channels are OPERABLE or in trip. such that the feedwater and main turbine high water level trip logic will generate a trip signal on a valid signal. This requires that two channels in one trip system be OPERABLE or in trip.

If the required channels cannot be restored to OPERABLE status or placed in trip, Condition C must be entered and its Required Action taken.

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is sufficient for the operator to take corrective action, and takes into account the 1-ikelihood of an event requiring actuation of feedwater and main turbine high water level trip instrumentation occurring (continued)

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Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES ACTIONS B. 1 (continued) during this period. It is also consistent with the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in LCO 3.2.2 for Required Action A. 1, since this instrumentation's purpose is to preclude a MCPR violation.

C.1 With the required channels not restored to OPERABLE status or placed in trip, THERMAL POWER must be reduced to

< 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. As discussed in the Applicability section of the Bases, operation below 25% 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 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is based on operating experience to reduce THERMAL POWER to < 25% RTP from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE The Surveillances are modified by a Note to indicate that RE(UIREMENTS 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 feedwater and main turbine high water level trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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 channel Survei.llance. That analysis demonstrated that the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ensures that a gross failure of instrumentation has not occurred. A (continued)

BFN-UNIT 2 B 3.3-57 Amendment

~ i Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES SURVEILLANCE SR 3.3.2.2.1 (continued)

REQUIREMENTS CHANNEL CHECK is normally a comparison of the parameter indicated on 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 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 limits.

The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with 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 will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Frequency of 92 days is based on reliability analysis (Ref. 2).

SR 3.3.2.2.3 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 (continued)

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Feedwater and Hain Turbine High Mater Level Trip Instrumentation B 3.3.2.2 BASES SURVEILLANCE SR 3.3.2.2.3 (continued)

REQUIREMENTS calibrations consistent with the plant specific setpoint methodology.

The Frequency is based upon the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

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 valves is included as part of this Surveillance and overlaps the LOGIC SYSTEM FUNCTIONAL TEST to provide complete testing of the assumed safety function. Therefore, if a valve is incapable of operating, the instrumentation would also be inoperable.

associated The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency.

REFERENCES 1. FSAR, Section 14.5.7.

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. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

BFN-UNIT 2 B 3.3-59 Amendment

0 PAM Instrumentation B 3.3.3.1 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 information 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 that are required for safety systems to accomplish their safety functions for Design Basis Events.

The instruments that monitor these variables are designated as Type A, Category 1, and non-Type A, Category 1, in accordance with Regulatory Guide 1.97 (Ref. 1).

The OPERABILITY of the accident monitoring instrumentation ensures that there is sufficient information available on selected plant parameters to monitor and assess plant status and behavior following an accident. This capability is consistent with the recommendations of Reference 1.

APPLICABLE The PAM'nstrumentation LCO ensures the OPERABILITY of SAFETY ANALYSES Regulatory Guide 1.97, Type A variables so that the control room operating staff can:

~ Perform the diagnosis specified in the Emergency Operating Instructions (EOIs). These variables are restricted to preplanned actions for the primary 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 instrumentation LCO also ensures OPERABILITY of Category 1, non-Type A', variables so that the control room operating staff can:

~ Determine whether systems important to safety are performing their intended functions; j

(continued)

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PAN Instrumentation B 3.3.3.1 BASES APPLICABLE ~ Determine the potential for causing a gross breach of SAFETY ANALYSES the barriers to radioactivity release; (continued)

~ Determine whether a gross breach of a barrier has occurred; and

~ Initiate action necessary to protect the public and for an estimate of the magnitude of, any impending threat.

The plant specific Regulatory Guide 1.97 Analysis (Ref. 2)

.documents the process that identified Type A and Category 1, non-Type A, .variables.

Accident monitoring instrumentation that satisfies the definition of Type A in Regulatory Guide 1.97 meets Criterion 3 of the NRC Policy Statement (Ref. 6). Category 1, non-Type A, instrumentation is retained in Technical Specifications (TS) because they are intended to assist operators in minimizing the consequences of accidents.

Therefore, these Category 1 variables are important for reducing public risk.

LCO LCO 3.3.3. 1 requires two OPERABLE channels for all but one Function to ensure that no single failure prevents the operators from being presented with the information necessary 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 validity of displayed information.

The exception to the two channel requirement is primary containment isolation valve (PCIV) position. In this case, the important information is the status of the primary containment penetrations. The LCO requires one position indicator for each active (e.g., automatic) PCIV. This is sufficient to redundantly verify the isolation status of each isolable penetration either via indicated status of the active valve and prior knowledge of passive valve 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 (continued)

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PAM Instrumentation B 3.3.3.1 BASES LCO indication for closed and deactivated .valves is not required (continued) to be OPERABLE.

The following list is a discussion of the specified instrument Functions listed in Table 3.3.3.1-1.

1. Reactor Steam Dome Pressure Reactor steam dome pressure is a Category ) variable provided to support monitoring of Reactor Coolant System (RCS) integrity and to verify operation of the Emergency Core Cooling Systems (ECCS). Two independent pressure transmitters with a range of 0 psig to 1200 psig monitor pressure. Wide range indicators are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.

2. Reactor Vessel Water Level Reactor vessel water level is a Category I variable provided to support monitoring of core cooling and to verify operation of the ECCS. Two different range water level channels (Emergency Systems and Post-accident Flood Range) provide the PAM Reactor Vessel Water Level Functions. The water level channels measure from I/3 of the core height to 221 inches above the top of the active fuel. Water 1'evel is measured by two independent differential pressure transmitters for each required channel. The output from these channels is indicated on two independent indicators, which is the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.

The reactor vessel water level instruments are not compensated for variation in reactor water density.

Function 2.a is calibrated to be most accurate at operational pressure and temperature while Function 2.b is calibrated to be most accurate for accident conditions.

{continued)

BFN-UNIT 2 B 3.3-62 Amendment

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PAM. Instrumentation B 3.3.3.1 LCO 3. Su ression Pool Mater Level (continued)

Suppression pool water level is a Category 1 variable pr'ovided to detect a breach in the reactor coolant pressure boundary (RCPB). This variable is also used to verify and provide long term surveillance of ECCS function. The wide range suppression pool water level measurement provides the operator with sufficient information to assess the status of both the RCPB and the water supply to the ECCS. The wide range water level indicators monitor the suppression pool water level from two feet from the bottom of the pool to five feet above normal water level. Two wide range suppression pool water level signals are transmitted from separate differential pressure transmitters and are continuously recorded and displayed on one recorder and one indicator in the control room. The recorder and indicator are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.

4. Or well Pressure Drywell pressure is a Category 1 variable provided to detect breach of the RCPB and to verify ECCS functions that operate to maintain RCS integrity. Two different ranges of drywell pressure channels (normal and wide range) receive signals that are transmitted from separate pressure transmitters and are continuously recorded and displayed on two control room recorders and two control room indicators. These recorders and indicators are the primary indication used 'by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.

5. Primar Containment Area Radiation Hi h Ran e Primary containment area radiation (high range) is 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. Two high range primary containment area radiation signals are transmitted from separate radiation detectors and are continuously recorded and displayed on two control room recorders. These recorders are the primary indication used (continued)

BFN-UNIT 2 B 3.3-63 Amendment

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PAM Instrumentation B 3.3.3.1 BASES LCO 5. Primar Containment Area Radiation Hi h Ran e (continued) by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.

6. Primar Containment Isolation Valve PCIV Position PCIV position is provided for verification of containment integrity. In the case of PC IV position, the important information is the isolation status of the containment penetration. The LCO requires one channel of valve position indication in the control room to be OPERABLE for each active PCIV in a containment penetration flow path, i.e.,

two total channels of PCIV position indication for a penetration flow path with two active valves. For containment penetrations with only one active PCIV having control room indication, Note (b) requires a single channel of valve position indication to be OPERABLE. This is sufficient .to redundantly verify the isolation status of each isolable penetration via indicated status of the active valve, as applicable, and prior knowledge of passive valve or system boundary status. If a penetration flow path is isolated, position indication 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 indication for each PCIV consists of green and red indicator lights that illuminate to indicate whether the PCIV is fully open, fully closed, or in a mid-position.

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

7. Dr well and Torus H dro en Anal zers Drywell and torus hydrogen analyzers are Category 1 instruments provided to detect high hydrogen or oxygen concentration conditions that represent a potential for containment breach. The drywell and torus hydrogen concentration recorders al]ow the operators to detect trends in hydrogen concentration in sufficient time to initiate (continued)

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PAM Instrumentation B 3.3.3.1 BASES LCO 7. Dr well and Torus H dro en Anal zers (continued) containment atmospheric dilution if containment atmosphere approaches combustible limits. Hydrogen concentration indication is also important in verifying the adequacy of mitigating actions. High hydrogen concentration is measured by two independent analyzers and continuously recorded and displayed on one control room recorder and one control room

.indicator. The analyzers have the capability for sampling both the drywell and the torus. These indicators are the primary indication used by the operator during an accident.

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

8. Su ression Pool Water Tem erature Suppression pool water temperature is a Category 1 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 pool water temperature instrumentation allows operators to detect trends in suppression pool water temperature in sufficient time to take action to prevent steam quenching vibrations in the suppression pool. Sixteen temperature sensors are arranged in two groups of two independent and redundant. channels, located such that they are sufficient to provide a reasonable measure of bulk pool temperature. The outputs for the sensors are recorded on two independent recorders in the control room. These recorders are the primary indication used by the operator during an accident. Therefore, the PAN Specification deals specifically with this portion of the instrument channels.

9. Dr well Atmos here Tem erature Drywell atmosphere temperature is a Category 1 vari able 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. Two wide range drywell atmosphere temperature signals are transmitted from separate temperature transmitters and are continuously recorded and displayed on one control room recorder and one control'oom indicator. The recorder and indicator are the primary indications used by the operator during an accident.

(continued)

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PAM Instrumentation B 3.3.3.1 BASES LCO 9. Dr well Atmos here Tem erature (continued)

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

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 applicable 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 Note 1 has been added to the ACTIONS to exclude the MODE change restriction of LCO 3.0.4. This exception allows entry into the applicable MODE while, relying on the ACTIONS even though the ACTIONS may eventually require plant shutdown. This exception is acceptable due to the passive function of the instruments, the operator's ability to diagnose an accident using alternative instruments and methods, and the low probability of an event requiring these instruments.

Notes 2 and 3 have been provided to modify the ACTIONS related to PAM 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 for inoperable PAM instrumentation channels provide appropriate compensatory measures for separate Functions. As such, Note 2 has been provided to allow separate Condition entry for each inoperable PAM Function. Note 3 has been provided for Function 6 to allow separate Condition entry for each penetration flow path.

(continued)

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PAM Instrumentation B 3.3.3.1 BASES ACTIONS A. 1 (continued)

When one or more Functions have one required channel that is inoperable, the required inoperable channel must be restored to OPERABLE status .within 30 days. The 30 day Completion Time is based on operating experience and takes into account the remaining OPERABLE channels (or, in the case of a Function that has only one required channel, other non-Regulatory Guide 1.97 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 PAN instrumentation during this interval.

B.l If a channel has not been restored to OPERABLE status in 30 days, this Required Action specifies initiation of action in accordance with. Specification 5.6.6, which requires a written report to be submitted to the NRC. This report discusses the alternate method of monitoring, the results of the root cause evaluation of the inoperability, and i'dentifies proposed restorative actions. This 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 information provided by this

-instrumentation.

C.1 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 .is based on the relatively low probability of an event requiring PAN instrument operation and the availabil-ity of alternate means to obtain the required information. Continuous operation with two required channels in'operable in a Function is not acceptable because the alternate indications may not fully meet all performance qualification requirements applied to the PAM Therefore, requiring restoration of one

'nstrumentation.

inoperable channel of the Function limits the risk that the (continued)

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PAN Instrumentation B 3.3.3.1 BASES ACTIONS C. 1 (continued)

PAM Function will be in a degraded condition should an accident occur. Condition C is modified by a Note that excludes hydrogen monitor channels. Condition D provides appropriate Required Actions for two inoperable hydrogen monitor channels.

D. 1 When two hydrogen monitor channels are inoperable, one hydrogen monitor channel must be restored to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is based on the low probability of the occurrence of a LOCA,that would generate hydrogen in amounts capable of exceeding the flammability limit; and the length of, time after the event that operator action would be required to prevent hydrogen accumulation from exceeding this limit.

E.l 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 any Required Action of Condi,tion C or 0, as applicable, and the associated Completion Time has expired, Condition E is entered for that channel and provides for transfer to the appropriate subsequent Condition.

F. 1 For the, majority of Functions in Table 3.3.3.1-1, if any Required Action and associated Completion Time of Condition C or D are not met, the plant must be brought to a NODE in which the LCO not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. 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.

(continued)

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PAN Instrumentation B 3.3.3.1 BASES ACTIONS G.l (continued)

Since alternate means of monitoring primary containment area radiation have been developed and tested, the Required Action is not to shut down the plant, but rather to follow the directions of Specification 5.6.6. These alternate means may be temporarily installed if the normal PAN channel cannot be restored to OPERABLE status within the allotted time. The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAN channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAN channels.

SURVEILLANCE SR 3.3.3.1.1 REQUIREMENTS Performance of the CHANNEL CHECK for each required PAN instrumentation channel 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 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. The high radiation instrument channels should be compared to each other or to other containment radiation monitoring instrumentation.

Agreement criteria are determined by the plant 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 Frequency of 31 days is based upon plant operating experience, with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of (continued)

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PAN Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.1 (continued)

RE(UIRENENTS a given Function in any 31 day interval is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those displays associated with the required channels of this LCO.

SR 3.3.3.1.2 and SR 3.3.3.1.3 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 CALIBRATION consists of verifying the remote indications conform to actual valve positions.

The 92 day Frequency for CHANNEL CALIBRATION of the Drywell and Torus Hydrogen Analyzer is based on operating experience and vendor recommendations. The 18 month Frequency for CHANNEL CALIBRATION of all other PAN instrumentation in Table 3.3.3. 1-1 is based on operating experience and consistency with BFN refueling cycles.

REFERENCES 1. Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident,"

Revision 3, Hay 1983.

2. TVA Letter from L. M. Hills to H. R. Denton (NRC) dated April 30, 1984.

3. NRC Letter from S.C. Black to S. A. White (TVA), NRC Regulatory Guide 1.97 SER letter, dated June 23, 1988.

4. TVA General Design Criteria No. BFN-50-7307, Revision 4, "Post-Accident Honitoring," dated June 22, 1993.

5. NRC Letter from Joseph F. Williams to Oliver D.

Kingsley, Jr., "Regulatory Guide 1.97 - Boiling Water Reactor Neutron Flux Monitoring For the Browns Ferry Nuclear Plant, Units 1, 2, and 3," dated May 3, 1994.

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

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0 Backup Control System B 3.3.3.2 B 3.3 INSTRUMENTATION B 3.3.3.2 Backup Control System BASES BACKGROUND The Backup Control System provides the control room operator with sufficient instrumentation and controls to place and maintain the plant in a safe shutdown condition from a location other than the control room. This capability is necessary to protect against the possibility of the control room becoming inaccessible. A safe shutdown condition is defined as MODE 3. With the plant in MODE 3, the Reactor Core Isolation Cooling (RCIC) System, the safety/relief valves, and the Residual Heat Removal System 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 operate the RHR System for decay heat removal from outside the control room allow extended operation in MODE 3.

In the event that the control room becomes inaccessible, the operators can establish control at the backup control panel and place and maintain the plant in MODE 3.. Not all controls and necessary transfer switches are located at the backup control panel. Some controls and transfer switches will have to be operated locally at the switchgear, motor control panels, or other local stations. The plant automatically reaches MODE 3 following a plant shutdown and can be maintained safely in MODE 3 for an extended period of time.

The OPERABILITY of the Backup Control System control and instrumentation Functions ensures that there is sufficient information available on selected plant parameters to place and maintain the plant in MODE 3 should the control room become inaccessible.

APPLICABLE The Backup Control System is required to provide equipment SAFETY ANALYSES at appropriate lo'cations outside the control room with a design capability to promptly shut down the reactor to MODE 3, including the necessary instrumentation and controls, to maintain the plant in a safe condition in MODE 3.

(continued)

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4I Backup Control System B 3.3.3.2 BASES APPLICABLE The criteria governing the design and the specific system SAFETY ANALYSES requirements of the Backup Control System are located in (continued) 10 CFR 50, Appendix A, GDC 19 (Ref. 1) and Reference 2.

The Backup Control System .,is considered an important contributor to reducing the risk of accidents; as such, it meets Criterion 4 of the NRC Policy Statement (Ref. 3).

LCO The Backup Control System LCO provides the requirements for the OPERABILITY of the instrumentation and controls necessary to place and maintain the plant in NODE 3 from a location other than the control room. The instrumentation and controls typically required are listed in Table B 3.3.3.2-1.

The controls, instrumentation, and transfer switches are those required for:

~ Reactor pressure vessel (RPV) pressure control;

~ Decay heat removal;

~ RPV inventory control; and

~ Safety support systems, for the above functions, including Residual Heat Removal (RHR) Service Water, Emergency Equipment Cooling Water, and onsite power, including the diesel generators.

The Backup Control System is OPERABLE if all instrument control and control channels needed to support the backup function are OPERABLE. In some cases, Table B 3.3.3.2-1 may indicate that the required information or control capability is available from several'lternate sources. In these cases, the Backup Control System is OPERABLE as long as one channel of any of the alternate information or control sources for each Function is OPERABLE.

The Backup Control System instruments and control circuits 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 circuits will be OPERABLE if plant conditions require that the Backup Control System be placed in operation. I (continued)

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/gi Backup Control System B 3.3.3.2 BASES (continued)

APPLICABILITY The Backup Control System LCO is applicable in MODES

2. This is required so that the plant can be placed and 1'nd maintained in MODE 3 for an extended period of time from a location other than the control room.

This LCO is not applicable in MODES 3, 4, and 5. In these MODES, the plant is already subcritical and in a condition 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 is included that excludes the MODE change restriction of LCO 3.0.4. This exception al.lows entry into an applicable MODE while relying on the ACTIONS even though the ACTIONS may eventually require a plant shutdown. This exception is acceptable due to the low probability of an event requiring this system.

Note 2 has been provided to modify the ACTIONS related to Backup Control System Functions. 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 for inoperable Backup Control System Functions provide appropriate compensatory measures for separate Functions.

As such, a Note has been provided that allows separate Condition entry for each inoperable Backup Control System Function.

A.1 Condition A addresses the situation where one or more required Functions of the Backup Control System is inoperable. This includes any Function listed in Table B .3.3.3.2-1, as well as the control and transfer switches.

(continued)

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Backup Control System B 3.3.3.2 ACTIONS A. 1 (continued)

The Required Action is to restore the Function to OPERABLE status within 30 days. The Completion Time is based on operating experience and the low probability of an event that would require evacuation of the control room.

If the Required Action and associated Completion Time of Condition A are not met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Time is 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 RE(UI REMENTS Performance of the CHANNEL 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 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 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'ALIBRATION.

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 sensor or the signal processing equipment has drifted outside its limit. As specified in the Surveillance, a CHANNEL CHECK is only required for those channels that are normally energized.

(continued)

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Backup Control System 8 3.3.3.2 SURVEILLANCE SR 3.3.3.2. 1 (continued)

REQUIREMENTS The Frequency is based upon plant operating experience that demonstrates channel failure is rare.

SR 3.3.3.2.2 SR 3.3.3.2.2 verifies each required Backup Control System transfer switch and control circuit performs the intended function. This verification is performed from the backup control panel and locally, as appropriate. Operation of the equipment from the backup control panel is not necessary.

The Surveillance can be satisfied by performance of a continuity check. This will ensure that if the control room becomes inaccessible, the plant can be placed and maintained in MODE 3 from the backup control panel and the local control stations. Operating experience demonstrates that Backup Control System control channels usually pass the Surveillance when performed at the 18 month Frequency.

SR 3.3.3.2.3 and SR 3.3.3.2.4 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. The test verifies the channel responds to measured parameter values with the necessary range and accuracy.

The Frequency of SR 3.3.3.2.3 is based upon the assumption of a 184 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

The 18 month Frequency of SR 3.3.3.2.4 is based upon operating experience and consistency with the typical industry refueling cycle.

REFERENCES l. 10 GFR 50, Appendix A, GDC 19.

2. FSAR Section 7. 18.

3. NRC No..93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

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Backup Control System B 3.3.3.2 Table B 3.3.3.2-1 (Page 1 of 4)

Backu Control System Instrumentation and Controls REQUIRED NUMBER FUNCTION OF CHANNELS Instrument Parameter

1. Reactor Water Level Indication 1

2. Reactor Pressure Indication 1

3. Suppression Pool Temperature Indication 1 4~ Suppression Pool Level Indication 1

5. Drywell Pressure Indication 1

6. Drywell Temperature Indication 1

7. EECW Flow Indication 2 (1/Header)

8. RCIC Flow Indication 1

9. RCIC Turbine Speed Indication 1

10. RCIC Turbine Trip Alarm 1 RCIC Turbine Bearing Oil High Temperature 1 Alarm .

Transfer Control Parameter

12. MSRV Transfer & Control 3 (1/MSRV)

13. MSIV Transfer & Control (Closure Only) 8 (1/MSIV)

14. Main Steam Drain Line Isolation Valves 2 (1/valve)

15. RHRSW Pumps 12 (1/pump)

16. RHRSW Discharge Valves for 2 RHR Loop I Heat Exchangers (1/valve)

17. RCW Pumps 1D and 3D 2 (Trip Function Only) (1/pump)

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Oi Backup Control System B 3.3.3.2 Table B 3.3.3.2-1 (Page 2 of 4)

Backup Control System Instrumentation and Controls REQUIRED NUHBER FUNCTION OF CHANNELS Transfer Control Parameter continued

18. 4-kV Fire Pumps A, B, and C 3 (1/pump)

19. Recirculation System Sample Line Isolation 2 Valves (1/valve)

20. EECW Sectionalizing Valves 8 (1/val ve)

21. RHRSW to EECW Motor-Operated 2 Crosstie Valves (1/valve)

22. EECW Supply to RBCCW Heat Exchangers 6 (1/val ve)

23. Recirculation Pump Discharge Valve 1 (RHR Loop I LPCI)

24. RWCU Drain to Hain Condenser Hotwell Isolation Valve

25. RWCU Drain to Radwaste Isolation Valve 1

26. RBCCW Pump Controls 2 (1/pump)

27. Drywell Cooler RBCCW 10 Flow Control Valves (1/cool er)

28. Drywell Cooler Fan Controls 10 (1/cool er)

29. RHR Shutdown Cooling Inboard Containment 1 Isolation Valve

30. RHR Shutdown Cooling Outboard Containment Isolation Valve

31. RCIC Steam Supply Isolation Valves 2 (1/valve)

32. RCIC Steam Pot Drain Line 1 Steam Trap Bypass BFN-UNIT 2 B 3.3-77 Amendment

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Backup Control System B 3.3.3.2 Table B 3.3.3.2-1 (Page 3 of 4)

Backup Control System Instrumentation and Controls REQUIRED NUNBER FUNCTION OF CHANNELS Transfer Control Parameter continued

33. RCIC Steam Pot Drain to Main 1 Condenser Isolation (1 switch for 2 valves)

34. RCIC Drain to Radwaste Isolation 1 (1 switch for 2 valves)

35. RCIC Turbine Steam Supply Valve 1

36. RCIC Turbine Stop Valve 1

37. RCIC Pump Suction From Suppression Pool 2 (1/val ve)

38. RCIC Pump Suction From 1 Condensate Storage Tank

39. RCIC Lube Oil Cooler Cooling Water Supply

40. RCIC Pump Minimum Flow Bypass

41. RCIC Pump Discharge

42. RCIC Test Return to

'Condensate Storage Tank

43. RCIC Injection Valve to Reactor Vessel

44. RCIC Barometric Condenser Condensate Pump

45. RCIC Barometric Condenser Vacuum Pump

46. HPCI Turbine Steam Supply Valve (Isolation Function Only)

47. RHR Pump Controls 4 (1/pump)

48. RHR Loop I Motor Operated Val'ves 17 (1/val ve)

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Backup Control System B 3.3.3.2 Table B 3.3.3.2-1 (Page 4 of 4)

Backup Control System Instrumentation and Controls REQUIRED NUHBER FUNCTION OF CHANNELS Transfer Control Parameter continued

49. -Core Spray Pumps (Trip 8 Lock-out Function Only) (1/pump)

50. CRD Pump 1B 1

51. CRD Pump Discharge Valves 2 (1/valve)

52. Scram Discharge Volume Isolation 1 Pilot Valve BFN-UNIT 2 8 3.3-79 Amendment

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EOC-RPT Instrumentation B 3.3.4.1 B 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation BASES BACKGROUND The EOC-RPT instrumentation initiates a recirculation pump trip (RPT) to reduce the peak reactor pressure and power resulting from turbine trip or generator load rejection transients to provide additional margin to core thermal HCPR Safety Limits (SLs).

The need for the additional negative reactivity 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 rods may not be able to ensure that thermal limits are maintained by inserting sufficient negative reactivity during the first few feet of rod travel upon a scram caused by Turbine Control Valve (TCV) Fast Closure, Trip Oil Pressure - Low or Turbine Stop Valve (TSV) Closure. The physical 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, combined with relays, logic circuits, and fast acting circuit breakers that interrupt power from the recirculation pump motor generator (MG) set generators to each of the recirculation pump motors. The channels include electronic equipment (e.g.,

trip relays) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs an EOC-RPT signal to the trip logic. When the RPT breakers 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 EOC-RPT trip system is a two-out-of-two logic for each Function; thus, either,two TSV Closure or two TCV Fast Closure, Trip Oil Pressure Low signals are required for a trip system to actuate. If either trip system actuates, both recirculation pumps will trip. There 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)

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EOC-RPT Instrumentation B 3.3.

4.1 BACKGROUND

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 designed to trip the LCO, and recirculation pumps in the event of a turbine trip or APPLICABILITY generator load rejection to mitigate the increase in neutron flux, heat flux, and reactor pressure, and to increase the margin to the NCPR SL, The analytical methods and assumptions used in evaluating the turbine trip and generator load rejection are summarized 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 alone, resulting in an increased margin to the NCPR SL. Alternatively,, MCPR limits for an inoperable EOC-RPT, as specified in the COLR, are sufficient to prevent violation of the NCPR Safety Limit.

The EOC-RPT function is automatically disabled when turbine first stage pressure is < 30% RTP.

EOC-RPT instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 6).

The OPERABILITY of the EOC-RPT is dependent on the OPERABILITY of the individual instrumentation channel Functions. Each Function must have a required number of OPERABLE channels in each trip system, with their setpoints within the specified Allowable Value of SR 3.3.4. 1'.3. The setpoint is calibrated consistent with applicable setpoint methodology assumpti'ons (nominal trip setpoint). Channel OPERABILITY also includes the associated EOC-RPT breakers.

Each channel (including the associated EOC-RPT breakers) must also respond within its assumed response time.

Allowable Values are specified for each EOC-RPT Function specified in the LCO. Nominal trip setpoints are specified in the setpoint calculations. A channel is inoperable if its actual trip setpoint is not within its required Al-lowable Value. The nominal setpoints are selected to ensure that the setpoints-do not exceed the Allowable Value (continued)

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EOC-RPT Instrumentation B 3.3.4.1 APPLICABLE between successive CHANNEL CALIBRATIONS. Operation with a SAFETY ANALYSES, trip setpoint less conservative than the nominal trip LCO, and setpoint, but within its Allowable Value, is acceptable.

APPLICABILITY Each Allowable Value specified is more conservative than the (continued) analytical limit assumed in the transient and accident analysis in order to account for instrument uncertainties appropriate to the Function. 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., TSV position), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip relay) changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environmental effects (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.

The specific Applicable Safety Analysis, LCO, and Applicability discussions are listed below on a Function by Function basis.

Alternatively, since this instrumentation protects against a MCPR SL violation, with the instrumentation inoperable, modifications to the MCPR limits (LCO 3.2.2) may be applied to allow this LCO to be met. The MCPR penalty for the EOC-RPT inoperable condition is specified in the COLR.

Turbine Sto Valve- Closure Closure of the TSVs and a main turbine trip result in the loss of a heat sink that produces reactor pressure, 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 reactor power and aids the reactor scram in ensuring that the MCPR SL is not exceeded during the worst case transient.

(continued)

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EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE Turbine Sto Valve- Closure (continued)

SAFETY ANALYSES, LCO, and Closure of the TSVs is determined by measuring the position APPLICABILITY of each valve. There are two separate position switches associated with each stop valve, the signal from each switch being assigned to a separate trip channel. 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 a 30% RTP. This is normally

.accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening 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 EOC-RPT, from this Function on a valid signal. The TSV- Closure Allowable Value is selected to detect imminent TSV closure.

This protection is required, consistent with the safety analysis assumptions, whenever THERMAL POWER is w 30% RTP.

Below 30% RTP, the, Reactor Vessel Steam Dome Pressure -High and the Average Power Range Monitor (APRM) Fixed Neutron Flux- High Functions "of the Reactor Protection System (RPS) are adequate to maintain the necessary margin to the MCPR Safety. Limit.

Turbine Control Valve Fast Closure Tri Oil Pressure- Low Fast closure of the TCVs during a generator load rejection results in the loss of a heat .sink that produces reactor pressure, neutron flux, and heat flux transients. that must be limited. Therefore, an RPT is initiated on TCV Fast

-

Closure, Trip Oil Pressure Low in anticipation of the transients that would result from the closure of these valves. The EOC-RPT decreases 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 electrohydraulic control. fluid pressure at each control valve. There is one pressure transmitter associated with each control valve, and the signal from each transmitter is assigned to a separate trip channel. The logic for the TCV Fast Closure, Trip Oil Pressure Low Function is such that two or more TCVs must be closed (pressure transmitter trips)

(continued)

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EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE Turbine Control Valve Fast Closure Tri Oil Pressure- Low SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY to produce an EOC-RPT. This Function must be enabled at THERMAL POWER a 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this function. Four channels of TCV Fast Closure, Trip Oil Pressure Low, with two channels in each 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 Pressure Low Allowable Value is selected high enough to detect imminent TCV fast closure.

This protection is required consistent with the safety

)

analysis whenever THERNAL POWER is 30% RTP. Below 30% RTP, the Reactor Vessel Steam Dome Pressure High and the APRN Fixed Neutron Flux- High Functions of the RPS are adequate to maintain the necessary safety margins.

ACTIONS A Note has been provided to modify the ACTIONS related to EOC-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 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 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.

A.l With one or more channels inoperable, but with EOC-RPT trip capability maintained (refer to Required Actions B. 1 and B.2 Bases), the EOC-RPT System is capable of performing the intended function. However, the reliabi-lity and redundancy (continued)

BFN-UNIT 2 B 3.3-84 Amendment

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EOC-RPT Instrumentation B 3.3.4.1 ACTIONS A. 1 (continued) 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 limited time is allowed to restore compl.iance with the LCO. Because of the diversity of sensors available 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 an EOC-RPT, 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is provided to restore the inoperable channels (Required Action A. I) or apply the EOC-RPT inoperable NCPR limit.

Alternately, the inoperable channels may be placed in trip (Required Action A.2) since this would conservatively compensate for the inoperability, restore capability to accommodate a single fai,lure, and allow operation to continue. As noted, placing 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 br'eaker 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.

B.l and 8.2 Required Actions B. I and B.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in the Function not maintaining EOC-RPT trip capability. A Function is considered to be maintaining EOC-RPT trip capability when sufficient channels are OPERABLE or in trip, such that the EOC-RPT System will generate a trip signal from the given Function on a valid signal and both recirculation pumps can be tripped. Alternately, Required Action B.2 requires the NCPR limit for inoperable EOC-RPT, as specified in the COLR, to be applied. This also restores the margin to NCPR assumed in the safety analysis.

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time. is sufficient time for the operator to take corrective action, and takes into account (continued)

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EOC-RPT Instrumentation B 3.3.4.1 BASES ACTIONS B. 1 and B.2 (continued) the likelihood of an event requiring actuation of the

.EOC-RPT instrumentation during this period. It is also consistent with the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in LCO 3.2.2 for Required Action A. 1, since this instrumentation's purpose is to preclude a NCPR violation.

C.l With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to < 30% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is reasonable, based on operating experience, to reduce THERMAL POWER to < 30% RTP from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE 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 EOC-RPT trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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. 5) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not significantly reduce the probability that the recirculation pumps will trip when necessary.

SR 3.3.4.1.1 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 the assumptions of the current plant specific setpoint methodology.

The Frequency of 92 days is based on reliability analysis of Reference 5.

(continued)

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EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE SR 3.3.4.1.2 REQUIREMENTS (continued) This SR ensures that an EOC-RPT initiated from the, TSV- Clbsure and TCV Fast Closure, Trip .Oil Pressure Low Functions will not be inadvertently bypassed when THERMAL POWER is w 30% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint.

If any bypass channel's setpoint is nonconservative (i.e.,

the Functions are bypassed at a 30% 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 inoperable. Alternatively, the bypass channel can, be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met with the channel considered OPERABLE.

The Frequency of 18 months is based on engineering judgment and reliability of the components.

SR 3.3.4.1.3 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 calibrations consistent with the plant specific setpoint methodology.

The Frequency is based upon the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

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 a part of this test, overlapping the LOGIC SYSTEM FUNCTIONAL TEST, to provide complete testing of the associated safety function. Therefore, if a breaker is incapable of operating, the associated instrument channel(s) would also be inoperable.

(continued)

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EOC-RPT Instrumentation B 3.3.4.1 SURVEILLANCE SR 3.3.4.1.4 (continued)

RE(UIREMENTS The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed'ith the reactor at power.

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

REFERENCES 1. FSAR, Figure 7.9-2 (EOC-RPT logic diagram).

2. FSAR, Section 7.9.4.5.

3. FSAR, .Sections 14.5. 1. 1 and 14.5. 1.3.

4. FSAR, .Section 4.3.5.

5. GENE-770-06-1, "Bases For Changes To Surveillance Test Intervals And Allowed Out-Of-Service Times 'For Selected Instrumentation Technical Specifications,"

February 1991.

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

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ATWS-RPT Instrumentation B 3.3.4.2 B '3. 3 INSTRUMENTATION B 3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation BASES 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 recirculation pumps adds negative reactivity from the increase in steam voiding in the core area as core flow decreases. When Reactor Vessel Water Level Low or Reactor Steam Dome Pressure High setpoint is reached, the recirculation pump motor breakers trip.

The ATWS-RPT System (Ref. I) includes sensors, relays, bypass capability, circuit breakers, and switches that are.

necessary to cause initiation of an RPT. The channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. 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 independent trip systems, with two channels of Reactor Steam Dome Pressure High and two channels of Reactor Vessel Water Level Low in each .trip system. Each ATWS-RPT trip system is a two-out-of-two logic for each Function. Thus, either two Reactor Water Level Low or two Reactor Pressure -High signals are needed to trip a trip system. The outputs .of the channels in .a trip system are combined in a logic so that either trip system will trip both recirculation pumps (by tripping the respective motor breakers)'

There are two motor breakers provided for each of the two recirculation pumps for a total of four breakers. The output of each trip system is provided to both recirculation pump breakers.

(continued)

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ATWS-RPT Instrumentation B 3.3.4.2 BASES (continued)

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'f the NRC Policy Statement (Ref. 3).

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 OPERABLE channels in each trip system, with their setpoints within the specified Allowable Value of SR 3.3.4.2.3. The setpoint is calibrated consistent with applicable setpoint methodology assumptions (nominal trip setpoint). ATWS-RPT Channel OPERABILITY also includes the associated recirculation pump motor breakers. A channel is inoperable if its actual trip setpoint Allowable Value.

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

Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel 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 limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors.

The trip setpoints. are then determined accounting for the remaining instrument. errors (e.g., drift). The trip

=

setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and environmental effects are accounted for.

(continued)

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ATWS-RPT Instrumentation B 3.3.4.2 BASES APPLICABLE The individual Functions are required to be OPERABLE in SAFETY ANALYSES, MODE 1 to protect against catastrophic/multiple failures of LCO, and the Reactor Protection System by providing a diverse trip APPLICABILITY to mitigate the consequences of a postulated ATWS event.

(continued) The Reactor Steam Dome Pressure High and Reactor Vessel Water Level Low Functions are required to be OPERABLE in MODE 1, since the reactor is producing significant power and the recirculation system could be at high flow. During this MODE, the potential exists for pressure increases or low water level, assuming an ATWS event. In MODE 2, the reactor is at low power and. the recirculation system is at low flow; 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 significant 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 reactor remains subcritical; thus, an ATWS event is not significant. 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 RPV water level indicates the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result.

Therefore, the ATWS-RPT System is initiated at Level 2 to aid in maintaining level above the top of the active fuel. The reduction of core flow reduces the neutron flux and THERMAL POWER and, therefore, the rate of coolant boiloff.

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.

(continued)

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ATMS-RPT Instrumentation

.B 3.3.4.2 APPLICABLE a. Reactor Vessel Water Level - Low SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY Four channels of Reactor Vessel Water Level Low, with two channels in each trip system, are available and 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 Vessel Mater Level Low Allowable Value 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 Steam Dome Pressure-~Hi h Excessively high RPV pressure may rupture the RCPB.

An 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 potentia'lly result in fuel failure and overpressurization. The Reactor Steam Dome 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 termination of the ATWS event and, along with the safety/relief valves, limits the peak RPV pressure to less than the ASNE Section III Code limits.

The Reactor Steam Dome Pressure High signals are initiated from four pressure transmitters that monitor reactor steam dome pressure. Four channels of Reactor Steam Dome Pressure High, with two channels in each trip system, are available and are required to be OPERABLE to ensure that no single instrument failure can preclude an ATWS-RPT from this Function on a The Reactor Steam Dome Pressure High valid'ignal.

Allowable Value is chosen to provide an adequate margin to the ASNE Section III Code limits.

ACTIONS A Note has been provided to modify the ACTIONS related to ATWS-RPT instrumentation channels. Section 1.3, Completion (continued)

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ATWS-RPT Instrumentation B 3.3.4.2 BASES ACTIONS Times, specifies that once a Condition has been entered, (continued) 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 ATWS-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 ATWS-RPT instrumentation channel.

A.l and A.2 With one or more channels inoperable, but with ATWS-RPT capability for each Function maintained (refer to Required Actions..B. 1 and C. 1 Bases), the ATWS-RPT System is capable of performing the intended function. However, the reliability and redundancy of the ATWS-RPT instrumentation is reduced, such that a single failure in the remaining trip system could result in the inability 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 available 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. 1). 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, placing the channel in trip with no further restrictions is not allowed if the inoperable channel is the result of an since this may not adequately compensate inoperable breaker, 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 would result in an RPT), or if the inoperable channel Condition is the result entered of an its inoperable breaker, D must be and Required Actions taken.

(continued)

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ATWS-RPT Instrumentation B 3.3.4.2 ACTIONS B.l (continued)

Required Action B. 1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in the Function not maintaining ATWS-RPT trip capability. A Function is considered to be maintaining ATWS-RPT trip capability 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 motor breakers to be OPERABLE or in trip.

The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is sufficient for the operator to take corrective action (e.g., restoration or tripping 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.

C.1 Required Action C. 1 is intended to ensure that appropriate Actions are taken if multiple, inoperable, untripped channels within both Functions result in both Functions not maintaining ATWS-RPT trip capability. The description of a Function maintaining ATWS-RPT trip capability is discussed in the Bases for Required Action B. 1 above.

The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time is sufficient for the operator to take corrective action and takes into account the likelihood of an event requiring actuation of the ATWS-RPT instrumentation during this period.

D.1 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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The allowed Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is

. reasonable, 'based on operating experience, both to reach MODE 2 from full power conditions and to remove a (continued)

BFN-UNIT 2 B 3.3-94 Amendment

ili ATMS-RPT Instrumentation B 3.3.4.2 BASES ACTIONS D. l (continued) recirculation pump from service in an orderly manner and without challenging plant systems.

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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains ATWS-RPT trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.

This Note is based'n the reliability analysis (Ref. 2) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not significantly reduce the probability that the recirculation pumps will trip when necessary.

SR 3.3.4.2.1 Performance of the CHANNEL CHECK once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 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 CAL I BRAT ION.

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.

(continued)

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ATWS-RPT Instrumentation B 3.3.4.2 BASES SURVEILLANCE SR 3.3.4.2. 1 (continued)

REQUIREMENTS The Frequency is based upon operating experience that demonstrates channel failure is rare. 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 3.3.4.2.2 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 the assumptions of the current plant specific setpoint methodology.

The Frequency of 92 days is based on the reliability analysis of 'Reference 2.

SR 3.3.4.2.3 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. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Frequency is based upon the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.4.2.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channels The system functional test of the pump breakers is included as part of this Surveillance and overlaps the LOGIC SYSTEM FUNCTIONAL TEST to provide complete testing of the assumed safety function. Therefore, if a breaker is incapable of operating, the associated instrument channel(s) would be inoperable.

(continued)

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ATWS-RPT Instrumentation B 3.3.4.2 SURVEILLANCE SR 3.3.4.2.4 .(continued)

REQUIREMENTS The 18 month Frequency is based on the need to perform this Surveillance under .the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

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

REFERENCES 1. FSAR Section 7, 19.

2. GENE-770-06-1, "Bases for Changes To Surveillance Test Intervals and Al.lowed Out-of-Service Times For Selected Instrumentation Technical Specifications,"

'February 1991.

3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

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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 instrumentation 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 anticipated operational occurrences and Design Basis Accidents (DBAs), a wide range, of dependent and independent parameters are monitored.

The ECCS instrumentation 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 described in the Bases for LCO 3.5. 1, "ECCS-Operating."

Core S ra S ste The CS System may be initiated by automatic means. Each pump can be controlled manually by a control .room remote switch. Automatic initiation occurs for conditions of

Reactor Vessel Water Level Low Low Low, Level 1 or both Drywell Pressure-High and Reactor Steam Dome Pressure- Low.

Reactor water level and drywell pressure are monitored by four redundant transmitters, which are, in turn, connected to four trip units. The outputs of these trip units are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic (i.e., two trip systems) for each Function. The Reactor Steam Dome Pressure Low variable is monitored by two transmitters for each subsystem. The outputs from these transmitters are connected to relays arranged in a one-out-of-two logic.

The high drywell pressure initiation signal is a sealed in signal and must be manually reset. Upon receipt of an initiation signal, if normal AC power is available, the four core spray pumps start one at a time, in order, at 0, 7, 14, and 21 seconds. If normal AC power is not available, (continued)

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ECCS Instrumentation B 3.3.

5.1 BACKGROUND

Core S ra S stem (continued) the four core spray pumps start seven seconds after standby power becomes available. (The LPCI pumps start as soon as standby power is available.)

The CS test line isolation valve is closed on a CS initiation signal to allow full system flow assumed in the accident analyses.

The CS pump discharge flow 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 minimum flow setpoint to allow the full system flow assumed in the accident analysis.

The CS System logic also receives, signals from transmitters which monitor the pressure in the reactor to ensure that, before the injection valves open, the reactor pressure has fallen to a value below the CS System's maximum design pressure. Reactor pressure is monitored by four redundant transmitters, which are, in turn, connected to four trip units (two per subsystem). The outputs of the trip units are connected to relays whose contacts are arranged in a one-out-of-two logic for each CS subsystem.

Low Pressure Coolant In 'ection S stem The LPCI is an operating mode of the Residual Heat Removal (RHR) System, with two LPCI subsystems. The LPCI subsystems may be initiated by automatic or manual means. Automatic initiation occurs for conditions of Reactor Vessel Water

Level Low Low Low, Level 1 or both Drywell Pressure -High and Reactor Steam Dome Pressure Low. Each of these diverse variables is monitored by four redundant transmitters, which, in turn, are connected to four trip units. The outputs of the trip units are connected to relays whose contacts are arranged in a one-out-of-two- taken twice logic (i.e., two trip systems) for each Function.

(continued)

BFN-UNIT 2 B 3.3-99 Amendment

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ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND Low Pressure Coolant I ection S stem (continued)

Once an initiation signal is received by the LPCI control circuitry, the signal is sealed in until manually reset.

Upon receipt of an initiation signal, if normal AC powe} is available, the four RHR (LPCI) pumps start one at a time, in order,'t 0, 7, 14, and 21 seconds. If normal AC power is not available, the four pumps start simultaneously, with no delay, as soon as the standby power source is available.

Each LPCI subsystem's discharge flow is monitored by a flow switch. When a pump 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 setpoint, the valve is automatically closed. However, LPCI flow rates assumed in the LOCA analyses can be achieved with the minimum flow valve in the open position.

The RHR test line suppression pool cooling isolation, valve, suppression pool spray isolation valves, and containment spray isolation valves (which are also PCIVs) are also closed on a LPCI initiation. signal to allow the full system flow assumed in the accident analyses and maintain primary containment isolated in the event LPCI is not operating.

The LPCI System 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 multiple trip units. The outputs of the trip units are connected to relays whose contacts are arranged in a one-out-of-two taken .twice logic. Additionally, these instruments function to initiate closure of the recirculation pump discharge valves to ensure that LPCI flow does not bypass the core when it injects into the recirculation lines.

Low reactor water level in the shroud is detected by two additional instruments which inhibit the manual initiation of other modes of RHR (e.g., suppression pool cooling) when (continued)

BFN-UNIT 2 B 3.3-100 NENDHENT

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ECCS Instrumentation B 3.3.

5.1 BACKGROUND

Low Pressure Cool nt In 'ection S ste (continued)

LPCI is required. Manual overrides for the inhibit logic are provided.

i es ure Coola t ect o S ste The HPCI System may be initiated by either automatic or manual means. Automatic initiation occurs for conditions of Reactor Vessel Water Level Low Low, Level 2 or Drywell Pressure-High. Each of these variables is monitored by four redundant transmitters, which are, in turn, connected to multiple trip units. The outputs of 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 flow is monitored by a flow switch.

Upon automatic initiation, 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 minimum flow setpoint to allow the full system flow assumed in the accident analysis.

The HPCI test line isolation valve is closed upon receipt of a HPCI initiation signal to allow the full system flow assumed in the accident analysis.

The HPCI System also monitors the water levels in the HPCI pump supply header from 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 normal source. Upon receipt of a HPCI initiation signal, the CST suction 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 HPCI pump supply header from 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 in the, HPCI pump supply header from the CST. Either switch can cause the suppression pool suction valves to open and the CST suction valve to close.

(continued)

BFN-UNIT 2 B 3.3-101 AMENDMENT

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ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND r s e Coo ant I ec 'o S ste (continued)

The suppression pool suction val.ves 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 to close. The logic is two-out-of-two to provide high reliability of the HPCI System. The HPCI, System automatically restarts

if a Reactor Vessel Mater Level Low Low, Level 2 signal is subsequently received.

tomatic De ressur zat on S ste The ADS may be initiated by either automatic or manual means. Automatic initiation occurs when signals indicating Reactor Vessel Water Level Low Low Low, Level 1; Drywell Pressure-High or ADS High Drywell Pressure Bypass Timer; confirmed Reactor Vessel Water Level Low, Level 3; and CS or LPCI Pump Discharge Pressure-High are all present and the ADS Initiation Timer has timed out. There are two transmitters each for Reactor Vessel Water Level Low Low Low, Level 1 and Drywell Pressure-High, and one transmitter for confirmed Reactor Vessel Water Level Low, Level 3 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 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 alarm in the control room is annunciated when either of the ADS Initiation Timers is timing. Resetting the ADS initiation signals resets the ADS Initiation Timers.

(continued)

BFN-UNIT 2 B 3.3-102 NENDHENT

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ECCS Instrumentation B 3.3.

5.1 BACKGROUND

t ress o S ste (continued)

The ADS also monitors the discharge pressures of the four LPCI pumps and the four CS pumps. Each ADS trip system includes two discharge pressure permissive switches from two of the four CS pumps (A and B for one trip system and C and D for the other trip system) and one discharge pressure permissive switch for each LPCI pump. The signals are used as a permissive for ADS actuation, indicating that there is a source of core coolant available once the ADS has depressurized the vessel. CS pumps (A or B and either C or D) or any one of the four LPCI pumps is sufficient to permit automatic depressurization.

The ADS logic in each trip system is arranged in two strings. Each string has a contact from each of the following variables: Reactor Vessel Water Level Low Low Low, Level 1; Drywell Pressure-High; or Low Water Level Actuation Timer. One of the two strings in each trip system must also have a confirmed Reactor Vessel Water Level Low, Level 3. All 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 present to initiate an ADS trip system. Either the A'r B trip system will cause all the ADS relief valves to open. Once the Drywell Pressure-High signal, the ADS High Drywell Pressure Bypass 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).

Diesel Generators The DGs may be initiated by either automatic or manual means. Automatic initiation occurs for conditions of Reactor Vessel Water Level Low Low Low, Level 1 or both Drywell Pressure- High and Reactor Steam Dome Pressure-Low.

The DGs are also initiated upon loss of voltage signals.

(Refer to the'Bases for LCO 3.3.8.1, "Loss of Power (LOP)

Instrumentation," for a discussion of these signals.) Each of these diverse variables is monitored by four redundant transmitters, which are, in turn, connected to four trip (continued)

BFN-UNIT 2 B 3.3-103 AMENDMENT

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ECCS Instrumentation B 3.3.

5.1 BACKGROUND

d ( ( dl units. The outputs of the four trip units are connected to relays whose contacts are connected to a one-out-of-two taken twice logic to initiate, all eight DGs {A, B, C, D, 3A, 3B, 3C, and 3D). The DGs receive their initiation signals from the CS System initiation logic. The DGs can also be started manually from the control room and locally from the associated DG room. The DG initiation signal is a sealed in signal and must be manually reset. The DG initiation logic is reset by resetting the associated ECCS initiation logic.

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 voltage 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.)

mer e c E u'ent Coolin ater ECM S stem The EECW System, which distributes cooling water supplied by the RHR Service Water System pumps that are assigned as the principal supply to the EECW System (RHRSW pumps A3, B3, C3 and D3), may be initiated by automatic or manual means.

Automatic initiation occurs for conditions of Reactor Vessel Mater Level Low Low Low, Level 1 or Drywell Pressure-High with a Reactor Steam Dome Pressure-Low permissive. Each of these diverse variables is monitored by four redundant transmitters, which are, in turn, connected to four trip units. The EECM System receives its initiation signals from the DG initiation logic and the CS System initiation logic.

The two RHRSW pumps (83 and D3) assigned to EECM and powered from shutdown boards in Units 1 and 2 will start automatically in less than 32.5 seconds after starting of a diesel generator or 30 seconds for a core spray pump in Units 1 and 2. The two RHRSW pumps (A3 and C3) assigned to EECW and powered from shutdown boards in Unit 3 will start automatically in less than 32.5 seconds after starting of a diesel generator or 30 seconds for a core spray pump in Unit

3. In addition, the signals that start the A3 and C3 pumps and the B3 and D3 pumps also start the Bl and Dl pumps and the Al and Cl pumps, respectively, when they are valved into the EECW header.

(continued)

BFN-UNIT 2 B 3.3-104 AMENDMENT

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ECCS Instrumentation B 3.3.5.1 BASES (continued)

APPLICABLE The actions of the ECCS are explicitly assumed in the safety SAFETY ANALYSES, analyses of References 1, 2, and 3. The ECCS 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 (Ref. 5). Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.

The OPERABILITY of the ECCS instrumentation 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, with their setpoints within the specified Allowable Values, where appropriate. The setpoint is calibrated consistent with applicable setpoint methodology assumptions (nominal trip setpoint). Each ECCS subsystem must also respond within its assumed response time. Table 3.3.5.1-1, footnote (b),, is added to show that certain ECCS instrumentation Functions are also required to be OPERABLE to perform DG initiation and actuation of other Technical Specifications (TS) equipment.

Allowable Values are specified for each ECCS Function specified in the table. Nominal trip setpoints are specified in the setpoint cal'culations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS.

Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. A channel is inoperable if its actual trip setpoint is not within its required Allowable 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 analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined, accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived (continued)

BFN-UNIT 2 B 3.3-105 NENDNENT

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ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE in this manner provide adequate protection because SAFETY ANALYSES, instrumentation uncertainties, process effects, calibration LCO, and tolerances, instrument drift, and severe environment errors APPLICABILITY (for channels that must function in harsh environments as (continued) defined by 10 CFR 50.49) are accounted for.

In general, the individual Functions are required to be OPERABLE 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 is required to provide primary and secondary initiation signals.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed. below on a Function by Function basis.

Core S ra d Low Pressure Coo ant In 'ectio S stems 2.a. Re cto Vesse Water eve -Low Low Low Level 1 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.

The low pressure ECCS, associated DGs, and EECW System are initiated at Level 1 to ensure that core spray and flooding functions are available to prevent or minimize fuel damage.

The Reactor Vessel Water Level Low Low Low, Level 1 is one of the Functions 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 assumed in the analysis of the recirculation line break (Ref..2). The core cooling function of the ECCS, along with the scram action of the Reactor Protection System (RPS), 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 due to the actual water level (variable leg) in the vessel.

(continued)

BFN-UNIT 2 B 3.3-106 AMENDMENT

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ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE Re cto Ve sel Water eve ow ow ow eve SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY The Reactor Vessel Mater Level Low Low Low, Level I Allowable Value is chosen to allow time, for the low pressure injection/spray subsystems to activate and provide adequate cooling.

Four channels of Reactor Vessel Water Level Low Low Low, Level I'unction are only required to be OPERABLE when the ECCS, DG(s), or EECW System are required to be OPERABLE to ensure that no single instrument failure can preclude ECCS, DG, and EECM initiation. Refer to LCO 3.5.1 and LCO 3.5.2,

-"ECCS-Shutdown," for Applicability Bases for the low pressure ECCS subsystems; LCO 3.7.2, "Emergency Equipment Cooling (EECW) Systems and Ultimate Heat Sink (UHS)," for Applicability Bases for EECW System; and LCO 3.8.1, "AC Sources -Operating"; and LCO 3.8.2, "AC Sources -Shutdown,"

for Applicability Bases for the DGs.

I b .b Dr e essure i High pressure in the drywell could indicate a break in the reactor coolant pressure boundary (RCPB). The low pressure ECCS, associated DGs, and EECM System are initiated upon receipt of the Drywell Pressure-High Function in order to minimize the possibility of fuel damage. The Drywell Pressure-High Function, along with the Reactor Pressure- Low Function, is directly assumed in the analysis of the recirculation line break (Ref. 2). 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.

High drywell pressure signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside .primary containment.

The Drywell Pressure-High Function is required to be OPERABLE when the ECCS, DG, or EECM System are 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 Function are required to be OPERABLE in.NODES I, 2, and 3 'to ensure that no single instrument failure can preclude ECCS, DG, and (continued)

BFN-UNIT 2 B 3.3-107 NENDMENT

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ECCS Instrumentation B 3.3'.5.1 BASES APPLICABLE e Pr ssure- (continued)

SAFETY ANALYSES, L'CO, and EECW System initiation. In NODES 4 and 5, the Drywell APPLICABILITY Pressure-High Function is not required, 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, LCO 3.7.2'for Applicability Bases for the EECW System, and to LCO 3.8.1 for Applicability Bases for the DGs.

.c. eactor S earn ome Pressu e ow 'ect on Permissive and ECCS I tiation Low reactor steam dome pressure signals are used as permissives for the low pressure ECCS subsystems. This 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'aximum design pressure. The Reactor Steam Dome 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 Steam Dome Pressure- Low Function is directly assumed in the analysis of the recirculation 'line break (Ref. 2). 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.

The Reactor Steam Dome Pressure- Low signals are initiated from fout pressure transmitters that sense the reactor dome pressure.

The Allowable VaTue is low enough to prevent overpressurizing 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 Steam Dome 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. Refer to LCO 3.5. 1 and LCO 3.5.2 for Applicability Bases for the low pressure ECCS subsystems.

(continued)

BFN-UNIT 2 B 3.3-108 NENDHENT

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ECCS Instrumentation 8 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and The minimum flow instruments are provided to protect the APPLICABILITY associated CS pumps from overheating when the pump is (continued) 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 CS Pump Discharge Flow- Low Function is assumed to be OPERABLE and capable of closing the minimum flow valves to ensure that the CS flows assumed during the transients and accidents analyzed in References 1, 2, and 3 are 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 limits of 10 CFR 50.46.

One flow switch per CS subsystem is used to detect the associated subsystems'low rates. The logic is arranged such that each flow switch causes its associated minimum flow valve to open. The logic will close the minimum flow valve once the closure setpoint is exceeded. The Pump Discharge Flow- Low Allowable Values are high enough to ensure that the pump flow rate is sufficient to protect the pump, yet low enough (based on engineering judgment) to ensure that the closure of the minimum flow valve is initiated to allow full flow into the core.

Each channel of Pump Discharge Flow- Low Function (two CS channels) is only required to be OPERABLE when the associated ECCS is required to be OPERABLE to ensure that no single instrument failure can preclude the ECCS function.

Refer to LCO 3.5. 1 and LCO 3.5.2 for Applicability Bases for the low pressure ECCS subsystems.

Coolant In 'ection

~P<<-

l.e 2.f. Core i

S ra and Low Pressure Il l R1 The reaction of the low pressure ECCS pumps to an initiation signal depends on the availability of power. If normal power (offsite power) is not available, the four RHR (LPCI) pumps start simultaneously after the standby power source (four diesel generators) is available while the CS pumps start simultaneously after a seven-second time delay. This (continued)

BFN-UNIT 2 B 3.3-109 AMENDMENT

0 ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE l.e 2.f. Core S ra and Low Pressure Coolant In 'ection SAFETY'NALYSES, LCO, and APPLICABILITY time delay .allows the start of LPCI pumps to avoid (continued) overloading the diesel generators. When normal power is available, the CS and RHR pump starts are staggered by shutdown board (i.e., A pumps start at 0 seconds, B pumps start at 7 seconds, C pumps start at 14 seconds, and 0 pumps start at 21 seconds). The purpose of this time delay, when power is being provided from the normal power source (offsite), is to stagger, the start of the CS and LPCI pumps, thus limiting the starting transients on the 4. 16 kV shutdown buses. The CS and LPCI Pump Start -Time Delay Relays 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 not cause failure of the power sources.

There are four CS Pump and six LPCI Pump Start -Time Delay Relays when power is being provided from the normal power source, one in each of the pump start logic circuits (LPCI pumps C and D have two time delay relays). While each time delay relay is dedicated to a single pump start logic, a single failure of a CS or LPCI Pump Start -Time Delay Relay could result in the loss of normal power to a 4. 16 kV shutdown board due to a voltage transient on the associated shutdown bus (e.g., as in the case where ECCS pumps on one shutdown bus start simultaneously due to an inoperable time delay relay). This would result in the affected board being powered by the associated diesel. Ther'efore, the worst case single failure would be failure of a single pump to start due to a relay failure leaving seven of the eight low pressure ECCS pumps OPERABLE; thus, the single failure criterion .is met (i..e., loss of one instrument does not preclude ECCS initiation). Since the CS pumps are 50%

capacity pumps, the LOCA analysis does not take credit for a CS loop if one of the pumps is inoperable. Therefore, a loss of one

4. 16 kV shutdown board failure results in the RHR pump and one CS loop (two CS pumps) for the LOCA analysis. The Allowable Value for the CS and LPCI Pump (continued)

BFN-UNIT 2 B 3.3-110 AMENDMENT

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ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE l.e 2.f. Core S ra and Low Pressure Coolant In 'ection SAFETY ANALYSES, LCO, and APPLICABILITY Start Time Delay Relays is chosen to be long enough so that most of the starting transient of the first set of pumps is complete before starting the second set of pumps on the same

4. 16 kV shutdown bus and short enough so that ECCS operation is not degraded.

There are also four CS and six LPCI Pump Start-Time Delay Relays when power is being provided by the standby source, one in each of the pump start logic circuits (LPCI pumps C and 0 have two time delay relays). While each relay is dedicated to a single pump start logic, a single failure of a Pump Start-Time Delay Relay could result in the failure of the two low pressure ECCS pumps (CS and LPCI) powered from the same shutdown board, to perform their intended function (e.g., as in the case where both ECCS pumps on one shutdown board start simultaneously due to an inoperable time delay relay). This still leaves six of eight low pressure ECCS pumps OPERABLE; thus, the single failure criterion is met (i.e., loss of one instrument does not preclude ECCS initiation). As stated above, since the LOCA analysis does not take credit for a CS loop if one of the pumps is inoperable, the loss of a 4. 16 kV shutdown board effectively results in the loss of one LPCI pump and one CS loop (two CS pumps). The Allowable Value for the CS and LPCI Pump Start-Time Delay Relays is chosen to be long enough so that most of the starting transient for the LPCI pump is complete before starting the CS pump on the same 4. 16 kV shutdown board and short enough so that ECCS operation is not degraded.

Each CS and LPCI Pump Start -Time Delay Relay Function is required to be OPERABLE only when the associated CS and LPCI subsystems are required to be OPERABLE. Refer to LCO 3.5. 1 and LCO 3.5.2 for Applicability Bases for the CS and LPCI subsystems.

2.d. Reactor Steam Dome Pressure- Low Recirculation Dischar e Valve Permissive Low, reactor steam dome pressure signals are used as permissives for recirculation discharge valve closure. This ensures that the LPCI subsystems inject into the proper RPV (continued)

BFN-UNIT 2 B 3.3-111 ANENDHENT

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ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 2.d. Reactor Steam Dome Pressure- Low Recirculation SAFETY ANALYSES, Dischar e Valve Permissive (continued)

LCO, and APPLICABILITY location assumed in the safety analysis. The Reactor Steam Dome Pressure Low is one of the Functions assumed to be OPERABLE and capable of closing the valve during the transients analyzed in References 1 and 3. The core cooling function of the ECCS, along with the scram acti'on of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. The Reactor Steam Dome Pressure Low Function is directly assumed in the analysis of the recirculation line break (Ref. 2).

The Reactor Steam .Dome Pressure- Low signals are initiated from four pressure transmitters that sense the reactor dome pressure.

The Allowable Value is chosen to ensure that the valves close prior to commencement of LPCI injection flow into the core, as assumed in the safety analysis.

Four channel's of the Reactor Steam Dome Pressure Low Function are only required to be OPERABLE in NODES 1, 2, and 3 with the associated recirculation pump discharge valve open.. With the valve(s) closed, the function of the instrumentation has been performed; thus, the Function is not required. In NODES 4 and 5, the loop injection location is not critical since LPCI injection through the recirculation loop in either direction will still ensure that LPCI flow reaches the core (i.e., there is no significant reactor steam dome back pressure).

2.e.. Reactor Vessel Water Level - Level 0 The Level 0 Function is provided as a permissi,ve to allow the RHR System to be manually aligned from the LPCI mode to the suppression pool cooling/spray or drywell spray modes.

The permissive ensures that water in the vessel is approximately two thirds core height before the manual transfer is allowed. This ensures that LPCI is available to prevent or. minimize fuel damage. This function may be overridden during accident conditions as allowed by plant procedures. Reactor Vessel Water Level Level 0 Function is implicitly assumed in the analysis of the recirculation line break (Ref. 2) since the analysis assumes that no LPCI flow diversion occurs when reactor water level is below Level 0.

(continued)

BFN-UNIT 2 B 3.3-112 AMENDMENT

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ECCS,Instrumentation B 3.3.5.1 BASES APPLICABLE 2.e. Reactor Vessel Water Level - Level 0 (continued)

SAFETY ANALYSES, LCO, and Reactor Vessel Water Level Level 0 signals are initiated APPLICABILITY 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. The Reactor Vessel Water Level Level 0 Allowable Value is chosen to allow the low pressure core flooding, systems to activate and provide adequate cooling before allowing a manual transfer.

Two channels of the Reactor Vessel Water Level Level 0 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 assumed, and other administrative controls are adequate to control .the valves. that this Function isolates (since the systems that the valves are opened for are not required to be OPERABLE in MODES 4 and 5 and are normally not used).

HPCI S stem 3.a. Reactor Vessel Water Level - Low Low Level 2 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 analyzed in References 1, 2, and 3. The core cool'ing function of the ECCS, al'ong 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'rom four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

The Reactor Vessel Water Level. Low Low, Level 2 Allowable Value is high enough such .that for complete loss of (continued)

BFN-UNIT 2 B 3.3'-113 AMENDMENT

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ECCS Instrumentation B 3.3.5.1 APPLICABLE 3.a. Reactor Vessel Water Level - Low Low Level 2 SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY 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 l.

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.Applicability Bases.

3.b. Dr well Pressure- Hicih High pressure in the drywell could indicate a break in the RCPB. The HPCI System is initiated upon receipt of the Drywell Pressure High Funct'ion in order to minimize the possibility of -fuel damage. 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

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limits of 10 CFR 50.46.

High drywell pressure signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible to be indicative of a LOCA inside primary containment.

Four channels of the Drywell Pressure High Function are required to be OPERABLE 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 Applicability Bases.

3.. R V<<III I 1-~Hih High RPV water level indicates that sufficient cooling water inventory 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 main steam lines (MSLs). The Reactor Vessel Water Level High, Level 8 Function is not assumed in the accident and transient analyses. It was retained since it is a (continued)

BFN-UNIT 2 B 3.3-114 AMENDMENT

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ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 3.c. Reactor Vessel Water Level - Hi h Level 8 SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY potentially significant contributor to risk, thus it meets Criterion 4 of the NRC Policy Statement (Ref. 5).

Reactor Vessel Water Level-High, Level 8 signals for HPCI are initiated from two level transmitters from the narrow range water level measurement instrumentation. The Reactor

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Vessel Water Level High, Level 8 Allowable Value is chosen to prevent flow from the HPCI System from overflowing into the NSLs.

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 3.5.1 for HPCI Applicability Bases.

3.d. Condensate Header Level - Low Low level in. the CST indicates the unavailability of an adequate supply of makeup water from this normal source.

Normally the suction valves between HPCI and the CST are open and, upon receiving a HPCI initiation signal, water for HPCI injection would be taken from the CST. However, if the water level in the HPCI pump supply header from 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 must 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 is the suppression pool.

Condensate Header 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