ML042380250

Technical Specification Change (TS) 433 - 24 Month Fuel Cycle

ML042380250
Person / Time
Site:	Browns Ferry
Issue date:	08/16/2004
From:	Abney T Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
GL-91-004, TVA-BFN-TS-433
Download: ML042380250 (174)

Text

Tennessee Valley Authority, Post Office Box 2000, Decatur, Alabama 35609-2000 August 16, 2004 TVA-BFN-TS-433 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop: OWFN P1-35 Washington, D.C. 20555-0001 Gentlemen:

In the Matter of

)

Docket No. 50-259 Tennessee Valley Authority BROWNS FERRY NUCLEAR PLANT (BFN) UNIT 1 -

TECHNICAL SPECIFICATION CHANGE (TS) 433 -

24 MONTH FUEL CYCLE Pursuant to 10 CFR 50.90, Tennessee Valley Authority (TVA) is submitting a request for an amendment to license DPR-33 for BFN Unit 1. The proposed amendment extends the frequency of "once-per-cycle" from 18 months to 24 months in the affected TS Surveillance Requirements.

The proposed changes will allow Unit 1 to adopt a 24-month refueling cycle, and will result in a maximum surveillance interval of 30 months when employing the 25%

grace period allowed by Surveillance Requirement 3.0.2.

These changes were evaluated in accordance with the guidance provided in NRC Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle", dated April 2, 1991.

TVA has previously requested and NRC approved (References 1 through 3) an extension in the frequency of "once-per-cycle" from 18 months to 24 months for similar Browns Ferry Units 2 and 3 equipment and for Unit 1 equipment that is required to support Units 2 and 3 operations and maintain Unit 1 in a shutdown condition. A separate TS change was also submitted and approved (DO Pr-ied o. recyad papf

U.S. Nuclear Regulatory Commission Page 2 August 16, 2004 for the Reactor Water Cleanup System Main Steam Valve Vault High Temperature 24 month surveillance frequency (References 4 and 5).

The content of this submittal is based on TVA's previous applications for Units 2 and 3.

TVA has also previously requested approval to revise the Unit 1 TS (TS 430 -

Reference 6) in order to replace the power range portion of the existing Neutron Monitoring System with a General Electric digital Nuclear Measurement Analysis and Control Power Range Power Range Neutron Monitor retrofit design.

The proposed change would also allow the implementation of Average Power Range Monitor and Rod Block Monitor Technical Specification improvements and operation in an expanded core power/flow domain, the Maximum Extended Load Line Limit region.

Similarly, TVA has recently requested approval to extend the channel calibration frequencies and allowable values for several systems' high area temperature isolation instruments (TS 447 -

Reference 7).

This proposed 24 month fuel cycle TS change assumes that TS 430 and TS 447 (References 6 and 7) have been approved.

The review and approval of this TS change should be staged and coordinated by the NRC in such a manner as not to invalidate this assumption.

In addition, this proposed Technical Specification revises the frequency for Surveillance Requirement 3.5.1.12, which is the automatic power supply transfer for the Low Pressure Coolant Injection System.

However, TVA has recently requested approval to delete this surveillance (TS 427 -

Reference 8).

On September 6, 1996, TVA submitted TS Change 362, which was TVA's conversion package from Custom Technical Specifications to Improved Technical Specifications (Reference 9).

As part of that application, TVA noted that several changes for Unit 1 required validation prior to Unit 1 recovery or necessary changes made.

NRC noted these required validations in their Safety Evaluation that accompanied License Amendment 234, dated July 14, 1998 (Reference 10).

Several of these validations have been.

incorporated into this amendment.

TVA intends to restart Unit 1 on a 24 month fuel cycle and this proposed amendment is necessary to support the restart of Unit 1.

Therefore, TVA requests that the amendment be approved by September 1, 2005 and that the implementation of the revised TS be within 60 days of NRC approval.

U.S. Nuclear Regulatory Commission Page 3 August 16, 2004 TVA has determined that there are no significant hazards considerations associated with the proposed amendment and that the amendment qualifies for a categorical exclusion from environmental review pursuant to the provisions of 10 CFR 51.22(c)(9).

Additionally, in accordance with 10 CFR 50.91(b)(1), TVA is sending a copy of this letter and attachments to the Alabama State Department of Public Health. provides TVA's evaluation of the proposed amendment.

Enclosures 2 and 3 provide mark-ups of the proposed change to the Technical Specifications and updated Technical Specification pages, respectively. contains copies of the appropriate marked-up Unit 1 TS Bases pages, showing the associated changes. contains copies of the updated Unit 1 TS Bases pages, which show the resulting changes.

The TS Bases changes in Enclosures 4 and 5 are provided for information and do not require NRC approval.

There are no regulatory commitments associated with this submittal.

If you have any questions about this amendment, please contact me at (256)729-2636.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on August 16, 2004.

cere Manage of Licens-ng and ndustry Aff irs Enclos es:

1.

TVA val on of Proposed Amendment

2.

Proposed changes to the Technical Specifications (mark-ups)

3.

Proposed changes to the Technical Specifications (updated pages)

4.

Proposed changes to the Technical Specification Bases (mark-ups)

5.

Proposed changes to the Technical Specification Bases (updated pages)

References:

1.

TVA letter, T.E. Abney to NRC, dated June 12, 1998, "Browns Ferry Nuclear Plant (BFN) -

Units 1, 2, and 3 -

Technical Specification (TS) Change TS-390 -

Request for License Amendment to Support 24-month Fuel Cycles."

U.S. Nuclear Regulatory Commission Page 4 August 16, 2004

2.

TVA letter, T.E. Abney to NRC, dated August 14, 1998, "Browns Ferry Nuclear Plant (BFN) -

Units 1, 2, and 3 -

Technical Specification (TS) Change TS-390 Supplement 1 -

Request for License Amendment to Support 24-month Fuel Cycles."

3.

NRC letter, L. Raghavan to J.A. Scalice, dated November 30, 1998, "Issuance of Amendments -

Browns Ferry Nuclear Plants Units 1, 2, and 3 (TAC Nos. MA2081, MA2082, and MA2083)."

4.

TVA letter, T.E. Abney to NRC, dated August 20, 2002, "Browns Ferry Nuclear Plant (BFN) - Units 2 And 3 -

Technical Specifications (TS) Change 417 -

Reactor Water Cleanup System - Main Steam Valve Vault (MSVV) Area Temperature -

High -

Extension of Channel Calibration Surveillance Requirement Frequency."

5.

NRC letter, K.N. Jabbour to J.A. Scalice, dated November 26, 2002, "Browns Ferry Nuclear Plant, Units 2 and 3 -

Issuance of Amendments Regarding Extension of Surveillance Calibration Interval for Area Temperature Monitoring Instrumentation of the Main Steam Valve Vault (TAC Nos. MB6196 and MB6197).

6.

TVA letter, T.E. Abney to NRC, dated November 10, 2003, "Browns Ferry Nuclear Plant (BFN) Unit 1 -

Technical Specification 430 -

Power Range Neutron Monitor Upgrade with Implementation of Average Power Range Monitor and Rod Block Monitor Technical Specification Improvements and Maximum Extended Load Line Limit Analyses,"

7.

TVA letter, T.E. Abney to NRC, dated August 16, 2004, "Browns Ferry Nuclear Plant (BFN) -

Units 1, 2 and 3 -

Technical Specifications (TS) Change TS-447 -

Extension of Channel Calibration Surveillance Requirement Performance Frequency and Allowable Value Revision."

8.

TVA letter, T.E. Abney to NRC, dated July 8, 2004, "Browns Ferry Nuclear Plant (BFN) -

Unit 1 -

Technical Specification (TS) Change 427 -

Deletion of the Low Pressure Coolant Injection Montor-Generator Sets."

U.S. Nuclear Regulatory Commission Page 5 August 16, 2004

9.

TVA letter, T.E. Abney to NRC, dated September 6, 1996, "Browns Ferry Nuclear Plant (BFN) -

Units 1, 2, and 3 -

Technical Specification (TS) Change TS-362 -

Request to Convert TSs to Improved Standard TS (ISTS) Consistent with NUREG-1433, Revision 1."

10.

NRC letter, L. Raghavan to J.A. Scalice, dated July 14, 1998, "Amendment Nos. 234, 253 and 212 to Facility Operating License Nos. DPR-33, DPR-52, and DPR-68: Regarding Conversion to Improved Standard Technical Specifications for the Browns Ferry Nuclear Plant, Units 1, 2, and 3 (TAC Nos. M96431, M96432, and M96433)."

Enclosures:

cc (Enclosures):

State Health Officer Alabama State Department of Public Health RSA Tower -

Administration Suite 1552 P.O. Box 303017 Montgomery, Alabama 36130-3017 (Via NRC Electronic Distribution)

U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-3415 Mr. Stephen J. Cahill, Branch Chief U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-8931 NRC Senior Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, AL 35611-6970 Kahtan N. Jabbour, Senior Project Manager U.S. Nuclear Regulatory Commission (MS 08G9)

One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739

ENCLOSURE 1 BROWNS FERRY NUCLEAR PLANT (BFN)

UNIT 1 TECHNICAL SPECIFICATION CHANGE (TS-433) 24 MONTH FUEL CYCLE TVA EVALUATION OF PROPOSED AMENDMENT INDEX SECTION DESCRIPTION PAGE 1.0 2.0 3.0 4.0 5.0 6.0 7.0 Description Proposed Amendment

Background

Technical Analysis Regulatory Safety Analysis Environmental Considerations References El-l El-2 El-3 El-7 El-62 El-64 El-65 Table 1 Table 2 Figure 1 Non-Instrument Calibration Surveillances Instrument Calibration Surveillances Instrument Value Relationships Detailed Component Level Assessment of Surveillance Interval Extensions El-67 E1-71 E1-75 El-Al El -i

1.0 DESCRIPTION

This letter requests an amendment to license DPR-33 for BFN Unit 1. The proposed amendment extends the frequency of "once-per-cycle" from 18 months to 24 months in several Technical Specification Surveillance Requirements.

The proposed changes will allow Unit 1 to adopt a 24-month refueling cycle, and will result in a maximum surveillance interval of 30 months when employing the 25% grace period allowed by Surveillance Requirement 3.0.2.

The proposed Surveillance Requirement changes were evaluated in accordance with the guidance provided in NRC Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle", dated April 2, 1991.

Justification for these changes has also been provided in accordance with the guidance contained in Generic Letter 91-04.

TVA previously requested (References 1 and 2) an extension in the frequency of "once-per-cycle" Surveillance Requirements from 18 months to 24 months for Browns Ferry Units 2 and 3 and for Unit 1 equipment that is required to support Units 2 and 3 operations and maintain Unit 1 in a shutdown condition.

NRC approval was provided in Reference 3. A separate Technical Specification change was also submitted and approved for the Reactor Water Cleanup (RWCU) System main steam valve vault high temperature 24 month surveillance frequency (References 4 and 5).

The content of this submittal is based on TVA's previous applications for Units 2 and 3.

TVA has also previously requested approval to revise the Unit 1 Technical Specifications (TS 430 -

Reference 6) in order to replace the power range portion of the existing Neutron Monitoring System with a General Electric (GE) digital Nuclear Measurement Analysis and Control Power Range Power Range Neutron Monitor retrofit design.

The proposed change would also allow the implementation of Average Power Range Monitor (APRM) and Rod Block Monitor Technical Specification improvements and operation in an expanded core power/flow domain, the Maximum Extended Load Line Limit region.

Similarly, TVA has recently requested approval to extend the channel calibration frequencies and allowable values for several systems' high area temperature isolation instruments (TS 447 -

Reference 7).

This proposed 24 month fuel cycle Technical Specification change assumes that TS 430 and TS 447 (References 6 and 7) have been approved. The review and approval of this Technical Specification change should be staged and coordinated by the NRC in such a manner as not to invalidate this assumption.

In addition, this proposed Technical Specification revises the frequency for Surveillance E1-1

Requirement 3.5.1.12, which is the automatic power supply transfer for the Low Pressure Coolant Injection System.

TVA has recently requested approval to delete this surveillance (TS 427 -

Reference 8).

On September 6, 1996, TVA submitted Technical Specifications Change 362, which was TVA's conversion package from Custom Technical Specifications to Improved Technical Specifications.

As part of that application, TVA noted that several changes for Unit 1 required validation prior to Unit 1 recovery or necessary changes made.

Several of these validations have been incorporated into this amendment.

-TVA intends to restart Unit 1 on a 24 month fuel cycle and this proposed amendment is necessary to support the restart of Unit 1.

Therefore, TVA requests that the amendment be approved by September 1, 2005 and that the implementation of the revised TS be within 60 days of NRC approval.

2.0 PROPOSED AMENDMENT TVA divided the affected Unit 1 Technical Specification Surveillance Requirements into two groups:

Group 1 -

Group 2 -

Surveillance Requirements for which the proposed change from once per 18 months to once per 24 months does not constitute a change to an instrument calibration interval (non-instrument calibration Surveillance Requirements).

For example, pump and valve functional tests, flow tests, logic system functional tests and response time tests are Group 1 type Surveillance Requirements.

All other Surveillance Requirements (i.e., those for which the proposed change from once per 18 months to once per 24 months constituted an extended instrument calibration interval).

The Group 1 Surveillance Requirements are listed in Table 1 (See Page El-67).

The Group 2 Surveillance Requirements are listed in Table 2 (See Page E1-71).

As previously stated, TVA has recently requested approval to extend the channel calibration frequencies for several systems' high area temperature isolation instruments to 24 months (TS 447-Reference 7).

TS 447 temporarily created Surveillance Requirement 3.3.6.1.7, which required the performance of channel calibrations every 24 months.

This proposed Technical Specification (TS 433) revises Surveillance Requirement El-2

3.3.6.1.5, which required the performance of channel calibrations, from once every 18 months to once every 24 months.

This proposed Technical Specification makes Surveillance Requirement 3.3.6.1.7 redundant, deletes this Surveillance Requirement, and replaces the references to 3.3.6.1.7 with references to 3.3.6.1.5.

Enclosures 2 and 3 provide mark-ups of the proposed change to the Technical Specifications and updated Technical Specification pages, respectively. contains copies of the appropriate marked-up Unit 1 TS Bases pages, showing the associated changes. contains copies of the updated Unit 1 TS Bases pages, which show the resulting changes.

The TS Bases changes in Enclosures 4 and 5 are provided for information and do not require NRC approval.

3.0 BACKGROUND

Improved reactor fuels allow licensees to consider an increase in the duration of the fuel cycle for their facilities. The staff has reviewed requests for individual plants to modify surveillance intervals to be compatible with a 24-month fuel cycle and issued Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-month Fuel Cycle", to provide generic guidance for preparing such license amendment requests.

TVA intends to implement a 24-month fuel cycle for BFN Unit 1 as part of the restart program. A number of Surveillance Requirements can only be performed during a plant shutdown, while for other surveillances it is preferable to have the plant in a shutdown condition to avoid the possibility of inducing plant transients.

The current Unit 1 Technical Specifications currently require these Surveillance Requirements to be performed on an 18-month frequency, consistent with the 18-month fuel cycles.

Therefore, to synchronize these requirements with a 24-month fuel cycle, it is necessary to extend the existing 18-month surveillance frequencies to 24 months.

This change will allow TVA to take advantage of improved fuel designs which support a 24-month refueling interval.

E1-3

TVA has previously requested and NRC approved (References 1 through 3) an extension in the frequency of "once-per-cycle" from 18 months to 24 months for similar Browns Ferry Units 2 and 3 equipment and for Unit 1 equipment that is required to support Units 2 and 3 operations and maintain Unit 1 in a shutdown condition.

A separate Technical Specification change was also submitted and approved for the Reactor Water Cleanup System Main Steam Valve Vault High Temperature 24 month surveillance frequency (References 4 and 5).

TVA has compared the proposed change, reason for change, background information, and technical analysis submitted in support of this proposed amendment with the information provided by TVA and approved by NRC in References 1 through 5 for the previous Units 2 and 3, 24-month fuel cycle Technical Specification changes.

The comparison for each of these areas is provided below:

The proposed change to the Unit 1 Technical Specifications are primarily the same changes that were proposed and approved for Units 2 and 3. As discussed below, some changes are required due to subsequent Technical Specification changes that were submitted since the Units 2 and 3 changes were approved.

o In 1997, when the Units 2 and 3 Technical Specification changes were submitted (References 1 and 2), the Units 2 and 3 Technical Specifications reflected surveillance requirements for the upgraded digital Power Range Neutron Monitoring equipments 2.

This equipment has not been approved for installation on Unit 1. However, TVA has requested approval (TS 430) to revise the Unit 1 Technical Specifications '3) in order to install the upgraded digital Power Range Neutron Monitoring equipment. This proposed 24 month fuel cycle Technical Specification change assumes that TS 430 has been 1 NRC letter, J.F. Williams to O.D. Kingsley, dated September 11, 1997, "Issuance of Amendment -

Browns Ferry Nuclear Plant Unit 2 (TAC No. M92504)

(TS 353).

2 NRC letter, A.W. DeAgazio to J.A. Scalice, dated September 3, 1998, "Amendment No. 213 to Facility Operating License No. DPR-68: Power Range Neutron Monitor Upgrade with Implementation of Average Power Range Monitor and Rod Block Monitor Technical Specification Improvements and Maximum Extended Load Line Limit Analyses -

Technical Specification Change TS-353 (TAC No. M92505) 3 TVA letter, T.E. Abney to NRC, dated November 10, 2003, "Browns Ferry Nuclear Plant (BFN) Unit 1 -

Technical Specification 430 -

Power Range Neutron Monitor Upgrade with Implementation of Average Power Range Monitor and Rod Block Monitor Technical Specification Improvements and Maximum Extended Load Line Limit Analyses,'

El -4

approved.

o In 1997, when the Units 2 and 3 Technical Specification changes were submitted (References 1 and 2), the Units 2 and 3 Technical Specifications contained a Surveillance Requirement (Table 3.3.1.1-1, Function 13) for Low Scram Pilot Air Header Pressure Switches.

The Units 2 and 3 Technical Specifications were subsequently revised as part of a Technical Specification amendment(4) to reflect the removal of these switches.

The Low Scram Pilot Air Header Pressure Switches were not, and will not be, permanently installed on Unit 1. Therefore, this Unit 1 Technical Specification change is different from the Units 2 and 3 precedents by omission of the Low Scram Pilot Air Header Pressure Switches.

o TVA has recently requested approval to extend the channel calibration frequencies for several systems' high area temperature isolation instruments to 24 months (TS 447 -

Reference 7).

TS 447 temporarily created Surveillance Requirement 3.3.6.1.7.

This proposed Technical Specification makes Surveillance Requirement 3.3.6.1.7 redundant, deletes Surveillance Requirement 3.3.6.1.7, and replaces the references to 3.3.6.1.7'with references to 3.3.6.1.5.

The underlying reason for this Unit 1 change is the same as that which was previously submitted for the Units 2 and 3 Technical Specification change (i.e., to allow Unit 1 to adopt a 24-month refueling cycle).

In addition, TVA needs to maximize consistency between the Unit 1 and Units 2 and 3 Technical Specifications, operations and maintenance procedures and practices prior to restarting Unit 1.

• The background information provided in support of this Unit 1 change incorporates the same elements previously submitted in support of the Units 2 and 3 change.

4 NRC letter, K.N. Jabbour to J.A. Scalice, dated April 8, 2002, "Browns Ferry Nuclear Plant, Units 2 and 3 -

Issuance of Amendments to Remove the Low-Scram Pilot Air Header Pressure Switches (TAC Nos. MB2722 AND MB2723)

El -5

• The technical analysis submitted for this Unit 1 Technical Specification change incorporates the same elements previously submitted in support of the previous Technical Specification changes for Units 2 and 3. Differences are noted below.

o Since Units 2 and 3 were operating in 1998 when the previous Technical Specification change was submitted and Unit 1 has been in an extended outage since March 1985, additional reliance on generic and Units 2 and 3 operating experience was utilized in preparing supporting information for Unit 1 instruments.

o This Unit 1 Technical Specification change is being submitted with the current Unit 1 licensed thermal power limit being 3,293 megawatts. Unit 1 is currently in an extended outage.

When Unit 1 restarts, TVA intends to operate the plant at extended power uprate conditions (i.e., 3,952 megawatts thermal power).

Since Unit 1 will not operate at 3,293 megawatts, Unit 1 specific setpoint calculations were performed assuming operating conditions that reflect a power level of 3,952 megawatts.

These calculations are conservative with respect to the current licensed thermal power limit.

o For the Units 2 and 3 submittal, NPRDS failure data searches, for system comparison with the rest of the industry, were conducted for the 12 year period from 1985 through 1996.

NPRDS ceased operations at the end of 1996.

Since new data was no longer added and the failure module in NPRDS is no longer functional, NPRDS data was not reviewed for applicability to Unit 1.

o On September 6, 1996, TVA submitted 5 1 Units 1, 2, and 3 Technical Specifications Change 362 -

Improved Technical Specifications, which was TVA's conversion package from Custom Technical Specifications to Improved Technical Specifications.

As part of that application, TVA noted several changes for Unit 1 which required validation prior to Unit 1 recovery or necessary changes made.

NRC noted"6 these required validations in their Safety 5 TVA letter, T.E. Abney to NRC, dated September 6, 1996, "Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - Technical Specification (TS)

Change TS-362 -

Request to Convert TSs to Improved Standard TS (ISTS)

Consistent with NUREG-1433, Revision 1," Specification 3.3.1.2, Pages 11 and 12.

6 NRC letter, L. Rahghavah to J.A. Scalice, dated July 14, 1998, "Amendment Nos. 234, 253 and 212 to Facility Operating License Nos. DPR-33, DPR-52, and DPR-68: Regarding Conversion to Improved Standard Technical Specifications for the Browns Ferry Nuclear Plant, Units 1, 2, and 3 (TAC Nos. M96431, M96432, and M96433).0 El-6

Evaluation that accompanied License Amendment 234, dated July 14, 1998.

Several of these validations have been incorporated into this amendment as noted in Section 4.2.

4.0 TECHNICAL ANALYSIS

4.1 SURVEILLANCE FREQUENCIES OF 24 MONTHS Based on the following evaluation, TVA has concluded that the proposed Technical Specification changes in instrumentation surveillance frequency to a 24-month interval are consistent with the guidance of Generic Letter 91-04.

TVA's monitoring program is adequate for assessing the effects of the extended instrument calibration surveillance intervals on future instrument drift.

A.

Non-Instrument Calibration Surveillance Requirements The non-instrument drift related Surveillance Requirements requiring evaluation for extended surveillance intervals are listed in Table 1 (Page El-67).

Evaluations were performed in accordance with the guidance set forth in Generic Letter 91-04, which requires licensees to:

(1) Evaluate the effect on safety of the change in surveillance intervals to accommodate a 24-month fuel cycle.

This evaluation should support a conclusion that the effect on safety is small; (2) Confirm that historical maintenance and surveillance' data do not invalidate this conclusion; and (3) Confirm that the performance of surveillances at the bounding surveillance interval limit provided to accommodate a 24-month fuel cycle would not invalidate any assumption in the plant licensing basis.

In consideration of these confirmations, NRC stated that the licensees need not quantify the effect of the change in surveillance intervals on the availability of individual systems or components.

As described in detail below, each item in Table 1 was qualitatively evaluated (including consideration of safety function, Updated Final Safety Analysis Report (UFSAR) event type, and purpose of the surveillance test) to determine the potential effect of the extended test interval on plant safety.

These evaluations were based on the plant design and on the information contained in the BFN Technical Specifications and Bases.

The conclusion for each item is El -7

that the effect on plant safety is small.

These conclusions are supported by the results of an extensive survey of plant-specific and industry historical maintenance and surveillance data.

In addition to these evaluations, the UFSAR, Technical Specifications, and other applicable documentation were reviewed to determine if the proposed surveillance interval extensions would invalidate any licensing basis assumptions.

This review did not reveal any conflicts between surveillance extension to 30 months (24 months + 25%) and the assumptions in the plant licensing basis.

Additional details of the qualitative assessments and historical data review are provided in the following summaries for the three areas identified in Generic Letter 91-04.

Individual assessments for each of the Surveillance Requirements in the table are provided in. When considered appropriate, due to the common requirements relative to a specific system, a single assessment addresses more than one Surveillance Requirement.

1.

Summary of Qualitative Assessments for Individual Surveillance Requirements Each of the Surveillance Requirements was categorized into one of eight types (A through H), as indicated in the table.

The effect on plant safety from extending the 18-month surveillance interval to a 24-month interval for each of the eight surveillance categories is as follows:

A)

Functional Tests of systems/components not part of the primary success path for reactor shutdown Surveillance tests in this category are associated with equipment and component functions which do not contribute to the primary success path for reactor shutdown. Therefore, extending the surveillance interval from 18 to 24 months would have only a small effect on plant safety.

This category includes Scram Discharge Volume (SDV)

Vent and Drain Valves, Reactor Mode Switch (Shutdown Position), Backup Control System, and Reactor Core Isolation Cooling (RCIC) System.

B)

Response Time Tests This category includes the Scram Discharge Volume Vent and Drain Valves, and the Main Turbine Bypass System.

For both these systems, other more El -8

frequent testing of the equipment would indicate any serious degradation of response time.

Therefore, increasing the surveillance interval for the response time test from 18 to 24 months would have only a small effect on plant safety.

C)

Logic System Functional Tests Systems/components included in this category are Reactor Protection System (RPS), Feedwater/Main Turbine High Water Level, End-of-Cycle Recirculation Pump Trip (RPT), Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT), Emergency Core Cooling System (ECCS),

RCIC, Primary and Secondary Containment Isolation, and Control Room Emergency Ventilation (CREV).

This type of surveillance test is conducted to demonstrate the satisfactory functioning of the particular instrumentation logic as a complete system involving all the redundant features.

Such tests are intended to reveal the possibility of failure of individual circuit components which might not be discovered during the more frequent channel functional testing.

In all cases, the level of redundancy is such that multiple failures would be needed to seriously degrade the system safety function.

The more frequent channel functional testing throughout the fuel cycle ensures the safety function is preserved.

Therefore, changing the overall logic system functional test frequency from 18 to 24 months would have only a small effect on plant safety.

D)

Simulated Automatic Actuation Tests These tests involve the following systems and components:

RPS Power Monitoring, ECCS, Automatic Depressurization System (ADS), 480 Volt Motor Operated Valve (MOV) Boards, RCIC, Primary Containment Isolation, Excess Flow Check Valves, and Main Turbine Bypass.

This type of test is essentially a supplementary test to the individual channel functional tests of the instrumentation and mechanical equipment of each system which are performed more frequently during the fuel cycle.

While the simulated automatic actuation test provides for a complete test from sensor to actuated device, it is, nevertheless, a redundant test in terms of validating system performance.

As a result of functional redundancy within each El -9

system, together with the additional channel functional test throughout the fuel cycle, extending the surveillance period for the simulated automatic actuation tests from 18 to 24 months would have only a small effect on plant safety.

E)

Functional tests of systems/components supporting low frequency accident initiators Systems/components involved in this category are the Standby Liquid Control (SLC), High Pressure Coolant Injection (HPCI), Traversing Incore Probe, and Suppression Chamber-to-Drywell Vacuum Breakers.

The surveillance tests described by this category are essentially related to equipment which is required to respond to postulated accidents and events of relatively low frequency.

Due to the redundancy of function designed into this equipment, plus other supporting surveillance, extending these tests from 18 to 24 months would have only a small effect on plant safety.

F)

Functional tests of systems/components where redundancy exists and low failure rate experience This category includes the Main Steam Relief Valves and ADS Valves, and the Suppression Chamber-to-Drywell Vacuum Breakers.

Considering the nature of these tests, the redundancy of the equipment comprising the systems and the low failure rate experience, it is concluded that extending the surveillance from 18 to 24 months would have only a small effect on plant safety.

G)

Leak Rate Tests These tests are associated with the Primary Containment (Drywell to Suppression Chamber).

Leak testing experience obtained at the BFN units indicates that extending the surveillance interval from 18 to 24 months would have only a small effect on plant safety.

El -10

H)

Inspections One Surveillance Requirement is considered in this category and it relates to the SLC System.

Monitoring of the sodium pentaborate solution parameters on a monthly basis as prescribed ensures the requisite enrichment is maintained.

Therefore, extending the period between analyses of the sodium pentaborate enrichment from 18 to 24 months would have only a small effect on plant safety.

In summary, many of the affected systems and components have other forms of testing performed on a more frequent basis that would discover possible failures.

Others have multiple redundant channels and redundant functions that could accomplish the safety function.

2.

Summary of Historical Maintenance and Surveillance Data Historical maintenance and surveillance data from the following sources were reviewed to determine if this data supports the preceding conclusion about effect on safety:

• Limiting Conditions for Operation (LCO)

Tracking Logs;

• Problem Evaluation Reports (PERs);

• License Event Reports (LERs);

• Completed 24-month Surveillance Tests on similar equipment installed on Units 2 and 3; and

• Maintenance Rule.

Data from each program were compiled and evaluated for adverse trends or excessive failures for any system or similar component in Units 2 and 3. This evaluation did not reveal any adverse trends or excessive failures for any system or component that would have more than a small effect on plant safety.

3.

Confirm that assumptions in the plant licensing basis would not be invalidated Appendix J Leak Rate and American Society of Me'chanical Engineers (ASME) Inservice Testing Programs Generic Letter 91-04 provides guidance for resolving potential conflicts between 10 CFR 50, Appendix J requirements and changing the associated surveillance El-11

intervals from a nominal 18 to 24 months.

The Technical Specifications for BFN address Appendix J requirements in Section 5.5.12, Primary Containment Leak Rate Testing Program.

Additionally, the Technical Specifications for BFN address the ASME Inservice Testing requirements in Section 5.5.6, Inservice Testing Program.

Although specific reference is not made to ASME Inservice Testing in the generic letter, the impact of 24-month refueling intervals on this program is addressed below for completeness.

1)

Primary Containment Leak Rate Testing Program (Technical Specification 5.5.12)

Plant documentation was reviewed, with regard to 10 CFR 50, Appendix J requirements, to determine if changes are required as a result of changing the fuel cycle length from 18 months to 24 months.

Appendix J requires periodic leak-rate testing of the primary containment isolation valves.

In October 1995, the NRC amended Appendix J, adding Option B, which established performance-based requirements.

The original prescriptive requirements of Appendix J were retained as Option A. Option B allows Types A, B, and C leak-rate testing intervals to be extended beyond' the originally-specified (Option A) intervals based on a demonstrated history of acceptable performance.

Implementation of Option B, as specified in Nuclear Energy Institute (NEI) report NEI 94-01, Revision 0 (Industry Guideline for Implementing Performance-based Option of 10 CFR 50, Appendix J, July 26, 1995), and endorsed by Regulatory Guide 1.163 (Performance-based Containment Leak-test Program, September, 1995) requires Type A testing to be performed at least once every 48 months, with extensions of up to once every 10 years based on acceptable performance.

Implementation of Option B requires Type B and C testing to be performed at least once every 30 months, with extensions of up to once every 10 years based on acceptable performance.

BFN has already implemented Option B, as reflected in the BFN Technical Specifications (Section 5.5.12, Primary Containment Leak Rate Testing Program).

Therefore, no exemptions or Technical El -12

Specification changes are required to comply with the guidance of Generic Letter 91-04.

2)

Inservice Testing Program (Technical Specification 5.5.6)

Inservice Testing (IST) surveillance requirements are controlled by the Inservice Testing Program required by Section 5.5.6 of the BFN Technical Specifications.

Because IST program details are located outside the Technical Specifications, the need for any specific Technical Specifications changes is precluded.

Any inservice testing which requires modification to accommodate the change from 18 to 24-month fuel cycles will be addressed by appropriate changes in the implementing plant procedures.

In summary, the non-instrument drift related Surveillance Requirements have been evaluated in accordance with the guidelines set forth in Generic Letter 91-04.

Extending the surveillance intervals to accommodate a 24-month fuel cycle would have only a small effect on plant safety.

B.

Instrument Calibration Surveillance Requirements of Generic Letter 91-04 states that Licensees should address several issues to provide an acceptable basis for increasing the calibration interval for instruments that are used to perform safety functions.

The NRC staff has identified a specific action that licensees should address for each of these issues in order to justify a proposed increase in the calibration interval.

Provided below is a summary of the recommended NRC actions contained in the Generic Letter, the applicable NRC issue from the Generic Letter, and the action TVA has taken to implement each recommended action and address each issue.

Following the discussion of TVA's response to the Generic Letter is a discussion of each affected Surveillance Requirement, the applicable system and instrument function, and the type of drift evaluation performed to justify the surveillance extension.

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RESPONSE TO GENERIC LETTER 91-04

1.

NRC RECOMMENDED ACTION:

Confirm that instrument drift as determined by as-found and as-left calibration data from surveillance and maintenance records has not, except on rare occasions, exceeded acceptable limits for a calibration interval.

NRC ISSUE:

The surveillance and maintenance history for instrument channels should demonstrate that most problems affecting instrument operability are found as a result of surveillance tests other than the instrument calibration.

If the calibration data show that instrument drift is beyond acceptable limits on other than rare occasions, the calibration interval should not be increased because instrument drift would pose a greater safety problem in the future.

TVA RESPONSE:

A review of BFN data indicated that there were only two occasions on Unit 2 since the units went to a 24 month calibration cycle, in which the as-found surveillance value was outside of the allowable values. An evaluation concluded that the 24 month calibration frequency for these instruments was still acceptable.

2.

NRC RECOMMENDED ACTION:

Confirm that the values of drift for each instrument type (make, model, and range) and application have been determined with a high probability and a high degree of confidence.

Provide a summary of the methodology and assumptions used to determine the rate of instrument drift with time based upon historical plant calibration data.

NRC ISSUE:

The licensee should have a body of as-found and as-left calibration data that permits the determination of the rate of instrument drift with time over the calibration interval.

This data should allow the determination of instrument drift for those instruments that perform safety functions.

TVA RESPONSE: The methodology used to perform the plant drift studies of the plant instrument surveillance data is documented in Reference 9. This methodology has been reviewed by the NRC and is consistent with NRC Regulatory Guide 1.105 (References 10 and 11).

A statistical evaluation was made of both instrument component and loop surveillance data to predict, within a 95%/95% confidence level, the E1-14

expected performance of an instrument component or loop based on the past performance of the instrument.

In some cases, there was insufficient data to perform a statistical evaluation.

For these instruments, vendor data or existing generic studies were used to conservatively determine a value for the drift.

To provide an adequate basis for the plant drift studies, the data for loops and components with similar characteristics were combined.

The surveillance data were analyzed to determine if the data were normally distributed.

A scatter plot of the data was developed and linear regression and least-squares curve analyses performed on the data to determine time dependency.

The corresponding accuracy values used in the instrument calculations were compared with the values from the drift study, and revisions were made to the calculation as necessary.

For example: The current calculation for the Reactor Vessel Water Level-Low, Level 3 ADS confirmatory signal, used an accuracy value of 0.774 inches of Water Column (inWC).

The drift study resulted in an accuracy value of 0.660 inWC.

For this new accuracy value, revised calculations confirmed that the margin to the Analytical Limit remained acceptable and that the current Technical Specifications allowable value is within the calculated allowable value band.

3.

NRC RECOMMENDED ACTION:

Confirm that the magnitude of instrument drift has been determined with a high probability and a high degree of confidence for a bounding calibration interval of 30 months for each instrument type (make, model number, and range) and application that performs a safety function.

Provide a list of the channels by Technical Specifications section that identifies these instrument applications.

NRC ISSUE:

The magnitude of the instrument drift error that occurs over a longer interval is an important consideration to justify an extension of the calibration interval for instruments that perform safety functions.

Licensees need to identify the applications where the calibration interval for these instruments depends upon the length of the fuel cycle and could be as long as 30 months (the extension limit for this calibration interval).

Licensees should determine the projected value of the instrument drift error that could occur over a 30-month interval for each of these applications.

El-15

TVA RESPONSE:

The drift performance was predicted with a 95%/95%

confidence level.

In some cases, there were insufficient data to perform a statistical evaluation.

For these instruments, vendor data or existing generic studies were used to conservatively determine a value for the drift.

The drift studies were performed for a 30 month cycle for each instrument type.

Where insufficient data existed to perform a drift study, instrument drift values were established from either vendor data or existing generic studies.

The affected instrument applications are listed in Table 2.

4.

NRC RECOMMENDED ACTION:

Confirm that a comparison of the projected instrument drift errors has been made with the values of drift used in the setpoint analysis.

If this results in revised setpoints to accommodate larger drift errors, provide proposed Technical Specifications changes to update trip setpoints.

If the drift errors result in a revised safety analysis to support existing setpoints, provide a summary of the updated analysis conclusions to confirm that safety limits and safety analysis assumptions are not exceeded.

NRC ISSUE:

Licensees should ensure that the projected value of instrument drift for an increased calibration interval is consistent with the values of drift errors used in determining safety system setpoints. These setpoints ensure that the consequences of accidents and anticipated transients are bounded within the assumptions of the safety analysis.

If the allowance for instrument drift that was used to establish trip setpoints for safety systems would be exceeded, licensees should establish new trip setpoints for safety systems.

El-16

Instrument Society of America (ISA) Standard, ISA-A67.04-1982, "Setpoints for Nuclear Safety-Related Instrumentation Used in Nuclear Power Plants," provides a methodology for evaluating instrument drift.

The NRC endorsed this standard in Regulatory Guide 1.105, "Instrument Setpoints for Safety-Related Systems."

If a new setpoint must be used to ensure that safety actions will be initiated consistent with the assumptions of the safety analysis, this will require a Technical Specifications revision to reflect a new trip setpoint value.

If the combination of instrument drift errors and current trip setpoints is not consistent with existing safety analysis assumptions, licensees should perform a new safety analysis to confirm that safety limits will not be exceeded with the increased drift associated with longer calibration intervals.

TVA RESPONSE:

Statistical evaluations were made of the Units 2 and 3 "as-found/as-left" surveillance data.

The results of these evaluations were used to confirm that the theoretical drift used in determining the allowable value and setpoint bounded the plant data.

In some cases, there was insufficient data to perform a statistical evaluation.

For these instruments, vendor data or existing generic studies were used to conservatively determine a value for the drift.

There was no impact on the instrument setpoints or Technical Specifications allowable values. There were no changes in the instrument analytical limits resulting from additional drift considerations; therefore, additional safety analyses were not required.

5.

NRC RECOMMENDED ACTION:

Confirm that the projected instrument errors caused by drift are acceptable for control of plant parameters to effect a safe shutdown with the associated instrumentation.

NRC ISSUE: Licensees should determine the effect of instrument errors on control systems used to effect a safe shutdown.

Licensees must confirm that the instrument errors caused by drift will not affect the capability to achieve a safe plant shutdown.

TVA RESPONSE:

The impact of the drift has been reviewed for each instrument setpoint calculation with a time dependent component.

Instruments without a time dependent component will not be impacted by 24-month cycles.

The calculations performed ensured that the current operating setpoints provide adequate margin to the Technical Specifications allowable values and the El -17

analytical limits.

Therefore, the projected instrument errors caused by drift are acceptable for control of plant parameters to achieve a safe shutdown.

6.

NRC RECOMMENDED ACTION:

Confirm that all conditions and assumptions of the setpoint and safety analyses have been checked and are appropriately reflected in the acceptance criteria of plant surveillance procedures for channel checks, channel functional tests, and channel calibrations.

NRC ISSUE:

Licensees should take care to avoid errors or oversights when establishing acceptance criteria for plant surveillance procedures that are derived from the assumptions of the safety analysis and the results of the methodology for determining setpoints. The NRC staff experience is that licensees have encountered problems when asked to confirm that instrument drift and other errors and assumptions of the safety and setpoint analyses are consistent with the acceptance criteria included in plant surveillance procedures.

This review should include channel checks, channel functional tests, and the calibration of channels for which surveillance intervals are being increased.

TVA RESPONSE:

The drift studies of the plant surveillance data and the setpoint analyses have been fully verified.

Results of setpoint calculation revisions will be incorporated into plant surveillance procedures prior to 24-month cycle operation.

7.

NRC RECOMMENDED ACTION:

Provide a summary description of the program for monitoring and assessing the effects of increased calibration surveillance intervals on instrument drift and its effect on safety.

NRC ISSUE:

Finally, licensees should have a program to monitor calibration results and the effect on instrument drift that will accompany the increase in calibration intervals. The program should ensure that existing procedures provide data for evaluating the effects of increased calibration intervals.

The data should confirm that the estimated errors for instrument drift with increased calibration intervals are within the limits projected.

E1-18

TVA RESPONSE:

To determine the effect of increasing the calibration intervals to 24-months, plant drift studies of the "as-found/as-left" surveillance data were performed for the instruments associated with the Surveillance Requirements listed in Table 2. Setpoint calculations were evaluated to determine the effects of the extended calibration interval on instrument accuraciss.

To meet the guidance documented in NRC Generic Letter 91-04, these plant drift studies were performed in accordance with the methodology in Reference 9.

This methodology has been reviewed by the NRC and is consistent with NRC Regulatory Guide 1.105 (References 10 and 11).

The statistical evaluation was made of both instrument component and loop surveillance data to predict, within a 95%/95% confidence level, the expected performance of an instrument component or loop based on the past performance of the instrument.

In some cases, there was insufficient data to perform a statistical evaluation.

For these instruments, vendor data or existing generic studies were used to conservatively determine a value for the drift.

Studies were performed for specific instruments where surveillance data were available.

To provide an adequate basis for the plant drift studies, the data for loops and components with similar characteristics were combined.

To compensate for variability in plant shutdowns, the studies were performed for 24 months + 25% (30 months total).

The plant drift studies resulted in repeatability values and the determination of time dependency.

The drift study value, based on surveillance data for groups of instruments, was compared to the appropriate accuracy value used in the setpoint calculation for these instruments.

If the plant data drift value was bounded by the current setpoint calculation value, no change in the current calculation was required.

If the plant data resulted in a 30 month drift value greater than the value used in the setpoint calculation, the value derived from the drift study was applied to the existing calculation.

If no drift study was available, an extended drift value was established from either vendor data or existing generic studies.

When a new value for drift was determined, it was used to revise the value in the instrument calculation.

The instrument setpoint and existing allowable value were then reconfirmed using the new drift value.

El -19

Figure 1 (see Page E1-75) illustrates the relationship between the setpoint (SP), the minimum and maximum acceptable allowable values [Av(min) and Av(max)] and the analytical limit (AL).

The upper half of the figure, starting with the SP, applies to a process that increases toward the AL.

The lower half of the figure applies to a process that decreases toward the AL.

Instrument drift error is included in the "Region of normal measurable uncertainties."

To provide operational reliability and ensure that the instrument will perform its design basis function, the Technical Specifications allowable value is established within the "Av Band."

Evaluation of a 30 month calibration interval showed that in essentially all cases the current values used in the setpoint calculations bound the derived field drift value. A review of BFN data indicated that there were only two occasions on Unit 2 since the units went to a 24 month calibration cycle, in which the as-found surveillance value was outside of the allowable values.

An evaluation concluded that the 24 month calibration frequency for these instruments was still acceptable.

This low number of occurrences confirms the validity of the process used to set the instruments.

In summary, based on the results of the studies described above, none of the instruments listed in Table 2 require a change in the Technical Specifications allowable value to accommodate a 24 month-nominal (30 month-maximum) calibration interval.

The setpoint calculations included the effects of extended power uprate operation.

Therefore, these results are applicable for 24-month calibration intervals considering extended power uprate operation.

Attention will continue to be paid to equipment performance by monitoring of affected instrument channels.

Recording of as-found and as-left values will continue routinely through TVA's surveillance program. A review is continuously performed through the work order program and failures are addressed through the corrective action program.

DISCUSSION OF SPECIFIC CHANGES Provided below is a discussion of each affected Surveillance Requirement, the applicable system and instrument function, and the type of drift evaluation performed to justify the surveillance extension.

E1 -20

1.

Technical Specifications:

3.3.1.1 -

RPS Instrumentation The impacted RPS instrumentation has been evaluated based on make, manufacturer, and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

Surveillance Requirement 3.3.1.1.13, Function 2.a, -

APRM Neutron Flux -

High, (Setdown)

This function is performed by In-core Neutron Detectors (Neutron Flux) providing inputs to a GE304A3719G005 NUMAC Power Range Neutron Monitor.

This monitor system's stability was evaluated by the vendor (GE). The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.1.1.13, Function 2.b, -

APRM Flow Biased Simulated Thermal Power -

High The flow sensing aspect of this function is performed by a Rosemount 1153DB6 transmitter.

The transmitter was evaluated using the methodology as described in Reference 9 against Rosemount Report D8900126 data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

El-21

Surveillance Requirement 3.3.1.1.13, Function 2.c, APRM Neutron Flux -

High This function is performed by In-core Neutron Detectors (Neutron Flux) providing inputs to a GE304A3719G005 NUMAC Power Range Neutron Monitor.

This monitor system's stability was evaluated by the vendor (GE).

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.1.1.13, Function 4, Reactor Vessel Water Level - Low, Level 3 This function is performed by a Rosemount 1153DB4 transmittersand 710DUOTT trip units.

The transmitter and trips unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount trip units are functionally checked and the setpoints are verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an extension in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount trip units with respect to drift.

Surveillance Requirement 3.3.1.1.13, Function 5, - Main Steam Isolation Valve (MSIV) -

Closure Since functional testing to confirm proper valve and limit switch operation is performed more frequently than every 18 months, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the limit switches with respect to drift.

Note, for the limit switches which are mechanical devices, misalignment is a more applicable term than drift.

El -22

Surveillance Requirement 3.3.1.1.13, Function 6, -

Drywell Pressure -

High This function is performed by a Rosemount 1153GB4 transmitter and 710DUOTT trip units.

The transmitter and trip units were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for these instruments.

The Rosemount trip units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an extension in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount trip units with respect to drift.

Surveillance Requirement 3.3.1.1.13, Function 7.a, -

SDV Water Level -

High Resistance-Temperature Device RTD This function is performed by a level measuring system (Fluid Components Inc. FR72-4HTRDLL) consisting of a sensor (RTD) and switch (Remote Electronics).

The sensor/switch was evaluated using the methodology as described in Reference 9.

The results of the evaluation indicated that the projected 30 month drift value for these instruments does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.1.1.13, Function 7.b, -

SDV Water Level -

High Float Switch This function is performed by Magnetrol 402-EP/VPX-S1MD4H switches which are a mechanical device in nature.

Therefore, there is no drift value associated with this function.

El -23

Surveillance Requirement 3.3.1.1.13, Function 8, -

Turbine Stop Valve -

Closure An increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the limit switches with respect to drift. Note, for the limit switches, which are mechanical devices, misalignment is a more applicable term than drift.

Surveillance Requirement 3.3.1.1.13, Function 9, -

Turbine Control Valve (TCV) Fast Closure, Trip Oil Pressure -

Low This function is performed by Barksdale TC 9622-3 switches.

The switches were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for these instruments does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.1.1.15, Function 8, -

Turbine Stop Valve Closure Bypass Function This function is performed by a Rosemount 1153GB8 transmitter and 710DUOTT trip units.

The transmitters and trip units were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for these instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The trip units are functionally checked and the setpoints are verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect these trip units with respect to drift.

Surveillance Requirement 3.3.1.1.15, Function 9, -

TCV Fast Closure, Trip Oil Pressure -

Low Bypass Function This function is performed by a Rosemount 1153GB8 transmitter and 710DUOTT trip units.

The transmitter and trip units were evaluated using the methodology as described in Reference 9 El -24

against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount trip units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount TRIP UNITS with respect to drift.

2.

Technical Specification 3.3.2.1 -

Control Rod Block Instrumentation The impacted Control Rod Block instrumentation has been, evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift>

falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

Surveillance Requirement 3.3.2.1.4, Function l.a, Rod Block Monitor Low Power Range -

Upscale Surveillance Requirement 3.3.2.1.4, Function l.b, Rod Block Monitor Intermediate Power Range -

Upscale Surveillance Requirement 3.3.2.1.4, Function 1.c, Rod Block Monitor High Power Range - Upscale Surveillance Requirement 3.3.2.1.4, Function l.e, Rod Block Monitor Downscale Surveillance Requirement 3.3.2.1.8, Function 1.a, Rod Block Monitor Low Power Range --

Upscale (Bypass)

Surveillance Requirement 3.3.2.1.8, Function 1.b, Rod Block Monitor Intermediate Power Range --

Upscale (Bypass)

E1-25

Surveillance Requirement 3.3.2.1.8, Function l.c, Rod Block Monitor High Power Range --

Upscale (Bypass)

These functions are performed by In-core Neutron Detectors (Neutron Flux) providing inputs, (through the APRM's) to a GE 304A3720G005 NUMAC Power Range Neutron Monitor's Rod Block Monitor function.

This monitor system's stability was evaluated by the vendor (GE). The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.2.1.5, Function 2, Rod Worth Minimizer 10% RTP Bypass Function This function is performed by a Foxboro IDP50-D22Cl1F transmitter (Feedwater Flow) as an input to the Foxboro Distributive System (Digital Feedwater Control).

This transmitter was evaluated using the methodology described in Reference 9, using a 30 month drift value.

3.

Technical Specifications 3.3.2.2 -

Feedwater and Main Turbine High Water Level Trip Instrumentation The impacted Feedwater and Main Turbine High Water Level Trip instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

E1 -26

Surveillance Requirement 3.3.2.2.3, -,

Feedwater and Main Turbine High Water Level Trip This function is performed by a Rosemount 1153DB4 transmitter and Rosemount 710DUOTT trip unit.

The transmitter and trip units were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount trip units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount trip units with respect to drift.

4.

Technical Specifications 3.3.3.1 -

Post Accident Monitoring Instrumentation The impacted Post Accident Monitoring instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

Surveillance Requirement 3.3.3.1.4, Function 2.a.,

Reactor Vessel Water Level -

Emergency Systems Range This function is performed by a Rosemount 1153DB5 transmitter.

The transmitter was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

El -27

Surveillance Requirement 3.3.3.1.4, Function 2.b, Reactor Vessel Water Level -

Post Accident Flood Range This function is performed by a Rosemount 1153DD5 transmitter.

This transmitter wase evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.3.1.4, Function 3, Suppression Pool Water Level This function is performed by a Rosemount 1154DP5 Transmitter.

This transmitter was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.3.1.4, Function 4.a, Drywell Pressure -

Normal Range This function is performed by a Rosemount 1153DB6 Transmitter.

This transmitter was evaluated using the methodology as described in Reference 9 against Rosemount Report D8900126 data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.3.1.4, Function 4.b, Drywell Pressure -

Wide Range This function is performed by a Rosemount 1154GP7 Transmitter.

This transmitter was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

E1 -28

Surveillance Requirement 3.3.3.1.4, Function 5, Primary Containment Area Radiation This function is performed by a GE 237X731G009/ GE 304A3700G036 NUMAC Radiation Monitor.

This monitor system's stability was evaluated by the vendor.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.3.1.4, Function 6, PCIV Position An increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the limit switches with respect to drift.

Note, for the limit switches which are mechanical devices, misalignment is a more applicable term than drift.

Surveillance Requirement 3.3.3.1.4, Function 8, Suppression Pool Water Temperature This function is performed by a Weed 612D-1A Temperature Element and a Bailey Controls 740311CAAN2 Voltage Converter.

The drift term for the converter was extrapolated linearly from 22.5 months to 30 months and evaluated using the methodology as described in Reference 9. The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the overall loop drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.3.1.4, Function 9, Drywell Atmosphere Temperature This function is performed by a Weed SP611-1A Temperature Element and a Transmation Inc. S-6501T Current Converter. The drift term for the converter was extrapolated linearly from 24 months to 30 months and evaluated using the methodology as described in Reference 9. The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the overall loop drift allowance provided in the setpoint calculation for this instrument.

E1-29

5.

Technical Specifications 3.3.3.2 -

Backup Control System Instrumentation The impacted Backup Control System instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

Surveillance Requirement 3.3.3.2.2 -

Suppression Pool Water Level This function is performed by a Fluid Components Inc., CL86 Transmitter.

This transmitter was evaluated using the methodology as described in Reference 9. The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.3.2.3 -

Each required instrument channel except Suppression Pool Water Level (see Bases, Table B 3.3.3.2-1):

1.

Reactor Water Level Indication

2.

Reactor Pressure Indication

3.

Suppression Pool Temperature Indication

4.

Suppression Pool Level Indication (see Surveillance Requirement 3.3.3.2.2)

5.

Drywell Pressure Indication

6.

Residual Heat Removal (RHR) Flow Indication

7.

RCIC Flow Indication

8.

RCIC Turbine Speed Indication

9.

Drywell Temperature Indication

10.

RHR Service Water (RHRSW) Header Pressure E1 -30

Discussions:

1.

This function is performed by a Rosemount 3051S transmitter and a Yokogawa 180 Indicator.

This transmitter was evaluated using five year drift data provided by the manufacturer. The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

This indicator was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

2.

This function is performed by a Rosemount 3051S Transmitter and a Yokogawa 180 indicator.

This transmitter was evaluated using five year drift data provided by the manufacturer. The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

This indicator was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

3.

This function is performed by an American Standard Type T Thermocouple.

This thermocouple was evaluated using the methodology as described in Reference 9. The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

4.

See Surveillance Requirement 3.3.3.2.2 E1 -31

5.

This function is performed by a Rosemount 1153DB6 Transmitter.

The transmitter was evaluated using the methodology as described in Reference 9 against Rosemount Report D8900126 data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

6.

This function is performed by a Rosemount 1153DF Transmitter and Moore SRT Modifier. The transmitter was evaluated using the methodology as described in Reference 9 against Rosemount Report D8900126 data.

The drift term for the modifier was extrapolated from 22.5 months to 30 months and evaluated using the methodology as described in Reference 4. The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

7.

This function is performed by a Rosemount 1153DF5TB Transmitter and a Yokogawa SLPC-281*E/NPR/HTB controller.

This transmitter was evaluated using the methodology as described in Reference 9. The drift term for the controller was obtained from the vendor (Yokogawa).

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the overall loop drift allowance provided in the setpoint calculation for this instrument.

8.

This function is for confirmation of operation by a GE 180 Indicator. No drift analysis is necessary.

9.

This function is performed by a Weed SP611-lA Temperature Element and a Transmation Inc. S-650T Current Converter.

The drift term for the converter was extrapolated linearly from 24 months to 30 months and evaluated using the methodology as described in Reference 9. The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the overall loop drift allowance provided in the setpoint calculation for this instrument.

E1-32

10.

This function is performed by GE 50-551032EAAK1 Transmitters and Rosemount 1151GP8G22B2 Transmitter. This GE transmitter was evaluated using the methodology as described in Reference 9 against plant calibration data.

The drift term for the Rosemount transmitter was extrapolated linearly to 30 months and evaluated using the methodology as described in Reference 9. The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the overall loop drift allowance provided in the setpoint calculation for this instrument.

6.

Technical Specifications 3.3.4.1 -

End of Cycle (EOC)

RPT Instrumentation The impacted EOC-RPT instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

Surveillance Requirement 3.3.4.1.2 - Turbine Stop Valve and TCV Closure Bypass Function This function is performed by a Rosemount 1153GB8 Transmitter and 710DUOTT Trip Units.

The transmitter and trip units were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for these instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The trip units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect these trip units with respect to drift.

E1 -33

Surveillance Requirement 3.3.4.1.3 -

Turbine Stop Valve -

Closure An increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the limit switches with respect to drift. Note, for the limit switches which are mechanical devices, misalignment is a more applicable term than drift.

Surveillance Requirement 3.3.4.1.3 -

TCV Fast Closure, Trip Oil Press. -

Low This function is performed by a Barksdale TC 9622-3 Switch.

The switch was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

7.

Technical Specifications 3.3.4.2 - ATWS-RPT Instrumentation The impacted ATWS-RPT instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

El -34

Surveillance Requirement 3.3.4.2.3, Function a, Reactor Vessel Water Level -

Low Low, Level 2 This function is performed by a Rosemount 1153DB5 Transmitter and GE MTU 184C5988 Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The GE Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing.

requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the GE Trip Units with respect to drift.

Surveillance Requirement 3.3.4.2.3, Function b, Reactor Steam Dome Pressure -

High This function is performed by a Rosemount 1152GP9 Transmitter and GE 184C5988 Trip Units. The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The GE Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the GE Trip Units with respect to drift.

8.

Technical Specifications 3.3.5.1 -

ECCS Instrumentation The impacted ECCS instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

E1 -35

Surveillance Requirement 3.3.5.1.5, Function l.a, Reactor Vessel Water Level -

Low Low Low, Level 1 This function is performed by a Rosemount 1153DB5 Transmitter and GE MTU 184C5988 Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument. The GE Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the GE Trip Units with respect to drift.

Surveillance Requirement 3.3.5.1.5, Function l.b, Drywell Pressure -

High This function is performed by a Rosemount 1153GB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

El-36

Surveillance Requirement 3.3.5.1.5, Function l.d, Core Spray Pump Discharge Flow -

Low (Bypass)

This function is performed by a Static-O-Ring 103AS-B212-NX-JJTTX6 Switch.

The switch was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function l.e, Core Spray Pump Start Time Delay Relay:-Pumps A, B, C, D

(with diesel power)

This function is performed by an Agastat ETR14D3DNM015 time delay relay upon implementation of the modifications for 24 month fuel cycle.

The new timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function l.e, Core Spray Pump Start Time Delay Relay: Pump A (with normal power)

This function is performed by an Agastat ETR14D3ANMO15 time delay relay.

The timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function l.e, Core Spray Pump Start Time Delay Relay: Pump B (with normal power)

This function is performed by an Agastat ETR14D3DNMO15 time delay relay.

The timer was evaluated using the methodology as described in Reference 8 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument E1 -37

does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function i.e, Core Spray Pump Start Time Delay Relay: Pump C (with normal power)

This function is performed by an Agastat ETR14D3DNMO15 time delay relay.

The timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function l.e, Core Spray Pump Start Time Delay Relay: Pump D (with normal power)

This function is performed by an Agastat ETR14D3DNMO15 time delay relay.

The timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function 2.a, Reactor Vessel Water Level -

Low Low Low, Level 1 This function is performed by a Rosemount 1153DB5 Transmitter and GE MTU 184C5988 Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The GE Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the GE Trip Units with respect to drift.

El -38

Surveillance Requirement 3.3.5.1.5, Function 2.b, Drywell Pressure -

High This function is performed by a Rosemount 1153GB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.5.1.5, Function 2.e, Reactor Vessel Water Level - Level 0 This function is performed by a Rosemount 1153DD5 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.5.1.5, Function 2.f, Low Pressure Coolant Injection (LPCI) Pump Start Time Delay Relay -

Pumps A, B, C, D (with diesel power)

This function is performed by an Agastat 7012S time delay relay.

The timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not E1-39

exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function 2.f, LPCI Pump Start Time Delay Relay: Pump A (with normal power)

This function is performed by an Agastat ETR14D3ANM015 time delay relay.

The timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function 2.f, LPCI Pump Start Time Delay Relay: Pump B (with normal power)

This function is performed by an Agastat ETR14D3DNMO15 time delay relay.

The timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function 2.f, LPCI Pump Start Time Delay Relay: Pump C (with normal power)

This function is performed by an Agastat ETR14D3DNMO15 time delay relay.

The timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function 2.f, LPCI Pump Start Time Delay Relay: Pump D (with normal power)

This function is performed by an Agastat ETR14D3DNMO15 time delay relay.

The timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

El -40

Surveillance Requirement 3.3.5.1.5, Function 3.a, Reactor Vessel Water Level-Low Low, Level 2 This function is performed by a Rosemount 1153DB5 Transmitter and GE MTU 184C5988 Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The GE Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the GE Trip Units with respect to drift.

Surveillance Requirement 3.3.5.1.5, Function 3.b, Drywell Pressure-High This function is performed by a Rosemount 1153GB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument. The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.5.1.5, Function 3.c, Reactor Vessel Water Level-High, Level 8 This function is performed by a Rosemount 1153DB4 Transmitter and Rosemount 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 El -41

month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.5.1.5, Function 3.f, HPCI Pump Discharge Flow-Low (Bypass)

This function is performed by an ITT Barton 289A Switch.

The switch was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function 4.a, Reactor Vessel Water Level-Low Low Low, Level 1 This function is performed by a Rosemount 1153DB5 Transmitter and GE MTU 184C5988 Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The GE Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged. Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the GE Trip Units with respect to drift.

Surveillance Requirement 3.3.5.1.5, Function 4.b, Drywell Pressure-High This function is performed by a Rosemount 1153GB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against E1-42

plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.5.1.5, Function 4.c, ADS Initiation Timer This function is performed by an Agastat ETR14D3GNMO15 time delay relay upon implementation of the modifications for 24 month fuel cycle.

The new timer was evaluated using the methodology as described in Reference 9 against plant calibration data. The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function 4.d, Reactor Vessel Water Level-Low, Level 3 (Confirmatory)

This function is performed by a Rosemount 1153DB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

E1 -43

Surveillance Requirement 3.3.5.1.5, Function 4.g, ADS High Drywell Pressure Bypass Timer This function is performed by an Agastat ETR14D3GNMO15 time delay relay upon implementation of the modifications for 24 month fuel cycle.

The new timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function 5.a, Reactor Vessel Water Level-Low Low Low, Level 1 This function is performed by a Rosemount 1153DB5 Transmitter and GE MTU 184C5988 Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument. The GE Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the GE Trip Units with respect to drift.

Surveillance Requirement 3.3.5.1.5, Function 5.b, Drywell Pressure-High This function is performed by a Rosemount 1153GB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an E1-44

increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.5.1.5, Function 5.c, ADS Initiation Timer This function is performed by an Agastat ETR14D3GNMO15 time delay relay upon implementation of the modifications for 24 month fuel cycle.

The new timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.5.1.5, Function 5.d, Reactor Vessel Water Level-Low, Level 3 (Confirmatory)

This function is performed by a Rosemount 1153DB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.5.1.5, Function 5.g, ADS High Drywell Pressure Bypass Timer This function is performed by an Agastat ETR14D3GNMO15 time delay relay upon implementation of the modifications for 24 month fuel cycle.

The new timer was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance El -45

provided in the setpoint calculation for this instrument.

9.

Technical Specifications 3.3.5.2 -

RCIC System Instrumentation The impacted RCIC System instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

Surveillance Requirement 3.3.5.2.3, Function 1, Reactor Vessel Water Level-Low Low, Level 2 This function is performed by a Rosemount 1153DB5 Transmitter and GE MTU 184C5988 Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The GE Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the GE Trip Units with respect to drift.

Surveillance Requirement 3.3.5.2.3, Function 2, Reactor Vessel Water Level-High, Level 8 This function is performed by a Rosemount 1153DB4 Transmitter and Rosemount 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data. The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent E1 -46

testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

10.

Technical Specifications 3.3.6.1 -

Primary Containment Isolation System Instrumentation The impacted Primary Containment Isolation System instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

Surveillance Requirement 3.3.6.1.5, Function l.a, Main Steam Line Isolation: Reactor Vessel Water Level-Low Low Low, Level 1 This function is performed by a Rosemount 1153DB5 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated. These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.6.1.5, Function l.b, Main Steam Line Isolation: Main Steam Line Pressure-Low This function is performed by a Rosemount 1153GB8 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint E1 -47

calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.6.1.5, Function l.c, Main Steam Line Isolation: Main Steam Line Flow-High This function is performed by a Rosemount 1153DD7 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.6.1.5, Function l.d, Main Steam Line Isolation: Main Steam Tunnel Temperature-High This function is performed by a Fenwall 17002-40 or EGS 01-170020-090 Switch.

The switch was evaluated using the methodology as described in Reference 9. The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

E1 -48

Surveillance Requirement 3.3.6.1.5, Function 2.a, Primary Containment Isolation: Reactor Vessel Water Level-Low, Level 3 This function is performed by a Rosemount 1153DB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.6.1.5, Function 2.b, Primary Containment Isolation: Drywell Pressure -

High This function is performed by a Rosemount 1153GB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.6.1.5, Function 3.a, HPCI Isolation: HPCI Steam Line Flow-High This function is performed by a Rosemount 1153DD7 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month E1-49

drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.6.1.5, Function 3.b, HPCI Isolation: HPCI Steam Supply Line Pressure-Low This function is performed by a Static-O-Ring 5N6-B3-U8-C1A-JJTTNQ Switch.

The switch was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.6.1.5, Function 3.c, HPCI Isolation: HPCI Turbine Exhaust Diaphragm Pressure-High This function is performed by a SOR 4N6-B5-U8-C1A-JJTTNQ Switch.

The switch was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.6.1.5, Function 4.a, RCIC Isolation: RCIC Steam Line Flow-High This function is performed by a Rosemount 1153DB5 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing El-50

requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.6.1.5, Function 4.b, RCIC Isolation: RCIC Steam Supply Line Pressure-Low This function is performed by a Static-O-Ring 5N6-B3-U8-ClA-JJTTNQ Switch.

The switches were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for these instruments do not exceed the drift allowance provided in the setpoint calculation for these instruments.

Surveillance Requirement 3.3.6.1.5, Function 4.c, RCIC Isolation: RCIC Turbine Exhaust Diaphragm Pressure-High This function is performed by a Barksdale P-lH-M85-SS Switch.

The switch was evaluated using the methodology as described in Reference 9 against plant calibration data.- The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.6.1.5, Function 5.a, RWCU Isolation: Main Steam Valve Vault (MSVV) Area Temperature-High The RWCU area temperature monitoring instrumentation, which is used for main steam line isolation, uses Weed brand RTDs (Model N9017D-lB-SP) coupled with Rosemount Analog Trip Units (ATUs) (Model 710DU).

A modification is planned, under 10 CFR 50.59, which will eliminate the bimetallic switches currently monitoring the MSVV area temperature and utilize the RTD/ATU instruments in the MSVV to provide both main steam line isolation and RWCU isolation.

E1 -51

The Setpoint and Scaling recalculation was performed in accordance with Reference 9, using both historical plant and vendor supplied drift data.

A statistical analysis of the historical data shows there was no time dependent variation of the accuracy.

The results of the evaluation indicated that the projected 30 month drift value does not exceed the allowance provided in the setpoint calculation.

The High Energy Line Break calculations for the MSVV rooms have also been redone and show that the physical location and response time of the Weed RTDs are satisfactory to detect and provide the required isolation function for high temperature in the MSVV within the current Technical Specification Allowable Values for instruments for the RWCU and main steam line isolation function.

Surveillance Requirement 3.3.6.1.5, Function 5.h, RWCU Isolation: Reactor Vessel Water Level-Low, Level 3 This function is performed by a Rosemount 1153DB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

E1-52

Surveillance Requirement 3.3.6.1.5, Function 6.a, Shut Down Cooling Isolation: Reactor Steam Dome Pressure-High This function is performed by a Static-O-Ring 5N6-B5-U8-ClA-JJTTNQ Switch.

The switch was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.6.1.5, Function 6.b, Shut Down Cooling (SDC) Isolation: Reactor Vessel Water Level-Low, Level 3 This function is performed by a Rosemount 1153DB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.6.1.5, Function 6.c., SDC Isolation: Drywell Pressure-High This function is performed by a Rosemount 1153GB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an E1 -53

increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

11.

Technical Specifications: 3.3.6.2 Secondary Containment System Isolation Instrumentation The impacted Secondary Containment System Isolation instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation. The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

Surveillance Requirement 3.3.6.2.3, Function 1, Reactor Vessel Water Level-Low, Level 3 This function is performed by a Rosemount 1153DB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.6.2.3, Function 2, Drywell Pressure-High This function is performed by a Rosemount 1153GB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint E1 -54

verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.6.2.3, Function 3, Reactor Zone Exhaust Radiation-High This function is performed by a GE 188C8941/

GE 304A3718G001 NUMAC Radiation Monitor.

This monitor's stability was evaluated by the vendor (GE).

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.6.2.3, Function 4, Refueling Floor Exhaust Radiation-High This function is performed by a GE 188C8941/GE 304A3718G001 NUMAC Radiation Monitor. This monitor's stability was evaluated by the vendor (GE).

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

12.

Technical Specifications:

3.3.7.1 -

CREV System Instrumentation The impacted CREV System instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

E1 -55

Surveillance Requirement 3.3.7.1.5, Function 1, Reactor Vessel Water Level-Low, Level 3 This function is performed by a Rosemount 1153DB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument. The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

Surveillance Requirement 3.3.7.1.5, Function 2, Drywell Pressure-High This function is performed by a Rosemount 1153GB4 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

E1 -56

Surveillance Requirement 3.3.7.1.5, Function 3, Reactor Zone Exhaust Radiation-High This function is performed by a GE 188C8941/GE 304A3718G001 NUMAC Radiation Monitor.

This monitor's stability was evaluated by the vendor (GE).

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Surveillance Requirement 3.3.7.1.5, Function 4, Refueling Floor Exhaust Radiation -

High This function is performed by a GE 188C8941/GE 304A3718G001 NUMAC Radiation Monitor. This monitor's stability was evaluated by the vendor (GE).

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

13.

Technical Specifications: 3.4.5 -

Reactor Coolant System (RCS) Leakage Detection System Instrumentation The impacted RCS Leakage Detection System instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

Surveillance Requirement 3.4.5.4 -

Required Leakage Detection System Instrumentation This function is performed by an Eberline SPING-3A Continuous Air Monitor (CAM).

This monitor was evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

E1 -57

14.

Technical Specifications:

3.6.1.5 -

Reactor Building-to-Suppression Chamber Vacuum Breakers Surveillance Requirement 3.6.1.5.3, Reactor Building-to-Suppression Chamber Vacuum Breakers: open setpoint This function is performed by a Rosemount 1153DB3 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 30 month drift values for the instruments do not exceed the drift allowance provided in the setpoint calculation for this instrument.

The Rosemount Trip Units are functionally checked and setpoint verified more frequently, and if necessary, recalibrated.

These more frequent testing requirements remain unchanged.

Therefore, an increase in the surveillance interval to accommodate a 24 month fuel cycle does not affect the Rosemount Trip Units with respect to drift.

4.2 VALIDATION ITEMS FROM CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS As part of TVA's conversion package from Custom Technical Specifications to Improved Technical Specifications, TVA noted that several changes for Unit 1 required validation prior to Unit 1 recovery or necessary changes made.

Several of these validations were explicitly for calibration frequencies and others were related to the instrument configuration that supported the calibration frequencies.

The evaluations performed to verify these calibration frequencies followed the same methodology described above for the 24 month calibration frequencies.

While no changes to the Unit 1 Technical Specifications are required, these validations partially satisfy the issues that would require staff acceptance before Unit 1 restart as noted in the Safety Evaluation for Amendment 234, which documented the conversion to Improved Standard Technical Specifications for Unit 1, and Unit 1 License Condition 2.C.4.

E1-58

A.

Calibration Frequencies Provided below is a discussion of each affected Surveillance Requirement, the applicable system and instrument function, and the type of drift evaluation performed to justify the surveillance frequency.

1.

Technical Specifications:

3.3.1.1 -

RPS Instrumentation The impacted RPS instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation. The following paragraph, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluation performed.

Surveillance Requirement 3.3.1.1.10, Function 3, -

Reactor Vessel Steam Dome Pressure -

High This function is performed by a Rosemount 1152GP9 Transmitter and 710DUOTT Trip Units.

The transmitter and trip unit were evaluated using the methodology as described in Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 7.5 month drift value for these instruments does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Therefore, the current 184 day calibration frequency is acceptable.

2.

Technical Specifications 3.3.5.1 - ECCS Instrumentation The impacted ECCS instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraph, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluation performed.

Surveillance Requirement 3.3.5.1.4, Functions Ic and 2c -

Reactor Steam Dome Pressure -

Low (Injection Permissive and ECCS Initiation; and Function 2d -

Reactor Steam Dome Pressure - Low (Recirculation Discharge Valve Permissive)

E1 -59

This function is performed by a Weed DTN2010 Transmitter and a Rosemount 710DUOTT trip Unit. The Weed transmitter has a 24 month drift value from the manufacturer which encompasses the required 7.5 month calibration interval.

The trip unit was evaluated using the methodology of Reference 9 against plant calibration data.

The results of the evaluation indicated that the projected 7.5 month drift value for this instrument does not exceed the drift allowance provided in the setpoint calculation for this instrument.

Therefore, the current 184 day calibration frequency is acceptable.

3.

Technical Specifications 3.3.6.1 -

Primary Containment Isolation System Instrumentation The impacted Primary Containment Isolation System instrumentation has been evaluated based on make, manufacturer and model number to determine that the instrumentation's actual drift falls within the assumed drift in the associated setpoint calculation.

The following paragraphs, listed by Surveillance Requirement and Function identify by make, manufacturer and model number the drift evaluations performed.

Surveillance Requirement 3.3.6.1.1, Function 3b, -

HPCI Steam Supply Line Pressure - Low This function is performed by Static-O-Ring 5N6-B3-U8-C1A-JJTTNQ Switch.

This instrument channel consists of pressure switches, which have no indication. An instrument check is a qualitative determination of acceptable behavior which is based upon observation of the instrument during operation.

These pressure switches have no indication function.

The functional test of the instrument that verifies operability, including the alarm and trip functions, is performed once per 92 days in accordance with Surveillance Requirement 3.3.6.1.2.

Therefore, not specifying an instrument check for this function is acceptable.

El -60

Surveillance Requirement 3.3.6.1.1, Function 3c, - HPCI Turbine Exhaust Diaphragm Pressure -

High This function is performed by a Static-O-Ring 4N6-B3-U8-C1A-JJTTNQ Switch.

This instrument channel consists of pressure switches, which have no indication.

An instrument check is a qualitative determination of acceptable behavior which is based upon observation of the instrument during operation.

These pressure switches have no indication function.

The functional test of the instrument that verifies operability, including the alarm and trip functions, is performed once per 122 days in accordance with Surveillance Requirement 3.3.6.1.2.

Therefore, not specifying an instrument check for this function is acceptable.

Surveillance Requirement 3.3.6.1.1, Function 4b, -

RCIC Steam Supply Line Pressure -

Low This function is performed by a Static-O-Ring 5N6-B3-U8-C1A-JJTTNQ Switch.

This instrument channel consists of pressure switches, which have no indication. An instrument check is a qualitative determination of acceptable behavior which is based upon observation of the instrument during operation.

These pressure switches have no indication function.

The functional test of the instrument that verifies operability, including the alarm and trip functions, is performed once per 122 days in accordance with Surveillance Requirement 3.3.6.1.2.

Therefore, not specifying an instrument check for this function is acceptable.

Surveillance Requirement 3.3.6.1.1, Function 4c, -

RCIC Turbine Exhaust Diaphragm Pressure - High This function is performed by a Barksdale PIH-M85SS Switch.

This instrument channel consists of pressure switches, which have no indication.

An instrument check is a qualitative determination of acceptable behavior which is based upon observation of the instrument during operation.

These pressure switches have no indication function.

The functional test of the instrument that verifies operability, including the alarm and trip functions, is performed once per 122 days in accordance with Surveillance Requirement 3.3.6.1.2.

Therefore, not specifying an instrument check for this function is acceptable.

E1 -61

The reviews described above validate the calibration frequencies identified during TVA's conversion from Custom Technical Specifications to Improved Technical Specifications.

B.

System Configurations During the conversion to the Improved Technical Specifications for Section 3.3.6.1, TVA noted that the physical configuration of the Unit 1 RWCU, HPCI and RCIC steam line break temperature monitoring functions were different from their Units 2 and 3 counterparts.

However, the proposed Improved Technical Specifications for Unit 1 were made consistent with Units 2 and 3. TVA stated that the configuration differences would be reconciled before Unit 1 recovery.

The design changes to make the Unit 1 RWCU, HPCI and RCIC steam line break temperature monitoring functions consistent with their Units 2 and 3 counterparts have been issued and will be implemented prior to entering the modes for which their respective Technical Specifications apply.

5.0 REGULATORY SAFETY ANALYSIS The Tennessee Valley Authority (TVA) is submitting an amendment request to license DPR-33 for the Browns Ferry Nuclear Plant (BFN) Unit 1.

5.1 No Significant Hazards Consideration TVA has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of Amendment", as discussed below:

1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response

No The proposed amendment changes the surveillance frequency from 18 months to 24 months for Surveillance Requirements in the Unit 1 Technical Specification that are normally a function of the refueling interval. Under certain circumstances, Surveillance Requirement 3.0.2 would allow a maximum surveillance interval of 30 months for these surveillances.

TVA's evaluations have shown that the reliability of protective instrumentation and equipment will be preserved for the maximum allowable surveillance interval.

The proposed changes do not involve any change to the design E1-62

or functional requirements of plant systems and the surveillance test methods will be unchanged.

The proposed changes will not give rise to any increase in operating power level, fuel operating limits, or effluents.

The proposed change does not affect any accident precursors.

In addition, the proposed changes will not significantly increase any radiation levels.

Based on the foregoing considerations and the evaluations completed in accordance with the guidance of Generic Letter 91-04, it is concluded that the proposed amendment does not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

Response

No The proposed amendment does not require a change to the plant design, nor the mode of plant operation. The proposed changes do not create the possibility of any new failure mechanisms.

No new external threats or release pathways are created.

Therefore, the implementation of the proposed amendment will not create a possibility for an accident of a new or different type than those previously evaluated.

3.0 Does the proposed amendment involve a significant reduction in a margin of safety?

Response

No The proposed amendment changes the surveillance frequency from 18 months to 24 months for Surveillance Requirements in the Unit 1 Technical Specification that are normally a function of the refueling interval. Under certain circumstances, Surveillance Requirement 3.0.2 would allow a maximum surveillance interval of 30 months for these surveillances.

Although the proposed Technical Specification changes will result in an increase in the interval between surveillance tests, the impact on system availability is small based on other, more frequent testing or redundant systems or equipment.

There is no evidence of any failures that would impact the availability of the systems.

This change does not alter the existing setpoints, Technical Specification allowable values or analytical limits.

The assumptions in the current safety analyses are not impacted and the proposed amendment does not reduce a margin of E1 -63

safety.

Therefore, the proposed license amendment does not involve a significant reduction in the margin of safety.

Based on the above, TVA concludes that the proposed amendments present no significant hazards consideration under the standards

• set forth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

5.2 Applicable Regulatory Requirements/Criteria The proposed Surveillance Requirement changes were evaluated in accordance with the guidance provided in NRC Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle", dated April 2, 1991.

Justification for these changes has also been provided in accordance with the guidance contained in Generic Letter 91-04.

Based on the evaluation presented above, TVA has concluded that the proposed Technical Specification changes in instrumentation surveillance frequency to a 24-month interval are consistent with the guidance of Generic Letter 91-04.

TVA's monitoring program is adequate for assessing the effects of the extended instrument calibration surveillance intervals on future instrument drift.

In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or the health and safety of the public.

6.0 ENVIRONMENTAL CONSIDERATION

A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10

'CFR 20, or would change an inspection or surveillance requirement.

However, the proposed amendment does not involve:

(i) a significant hazards consideration; (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite; or (iii) a significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Therefore, pursuant to 10 CFR 51.22(b), no El-64

environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

7.0 REFERENCES

1.

TVA letter to NRC, dated June 12, 1998, "Browns Ferry Nuclear Plant (BFN) -

Units 1, 2, and 3 -

Technical Specification (TS) Change TS-390 -

Request for License Amendment to Support 24-month Fuel Cycles."

2.

TVA letter to NRC, dated August 14, 1998, "Browns Ferry Nuclear Plant (BFN) -

Units 1, 2, and 3 -

Technical Specification (TS) Change TS-390 Supplement 1 -

Request for License Amendment to Support 24-month Fuel Cycles."

.3.

NRC letter to TVA, dated November 30, 1998, "Issuance of Amendments -

Browns Ferry Nuclear Plants Units 1, 2, and 3(TAC Nos. MA2081, MA2082, and MA2083)."

4.

TVA letter, T.E. Abney to NRC, dated August 20, 2002, "Browns Ferry Nuclear Plant (BFN) -

Units 2 And 3 -

Technical Specifications (TS) Change 417 -

Reactor Water Cleanup System -

Main Steam Valve Vault (MSVV) Area Temperature -

High -

Extension of Channel Calibration Surveillance Requirement Frequency."

5.

NRC letter, K.N. Jabbour to J.A. Scalice, dated November 26, 2002, "Browns Ferry Nuclear Plant, Units 2 and 3 -

Issuance of Amendments Regarding Extension of Surveillance Calibration Interval for Area Temperature Monitoring Instrumentation of the Main Steam Valve Vault (TAC Nos. MB6196 and MB6197).

6.

TVA letter, T.E. Abney to NRC, dated November 10, 2003, "Browns Ferry Nuclear Plant (BFN) Unit 1 -

Technical Specification 430 -

Power Range Neutron Monitor Upgrade with Implementation of Average Power Range Monitor and Rod Block Monitor Technical Specification Improvements and Maximum Extended Load Line Limit Analyses,"

7.

TVA letter, T.E. Abney to NRC, dated August 16, 2004, "Browns Ferry Nuclear Plant (BFN) -

Units 1, 2 and 3 -

Technical Specifications (TS) Change TS-447 -

Extension of Channel Calibration Surveillance Requirement Performance Frequency and Allowable Value Revision."

8.

EEB-TI-28, "Setpoint Calculations," Branch Technical Instruction, Revision 5, Tennessee Valley Authority, February 25, 2000.

E1-65

9.

TVA letter, T.E. Abney to NRC, dated July 8,

2004, "Browns Ferry Nuclear Plant (BFN) -

Unit 1 -

Technical Specification (TS) Change 427 -

Deletion of the Low Pressure Coolant Injection Montor-Generator Sets."

10.

NRC Regulatory Guide 1.105, "Instrument Setpoints for Safety-Related Systems," Revision 2, February 1986.

11.

NRC letter to TVA dated May 8,

1989, in regards to Notice of Violation (NRC Inspection Report Nos. 50-259/89-06, 50-260/89-06, and 50-296/89-06).

E1-66

TABLE 1 NON-INSTRUMENT CALIBRATION SURVEILLANCES SURVEILLANCE PAGE DESCRIPTION CATEGORY SR 3.1.7.6 3.1-25 SLC System: pump flow rate and discharge pressure E

SR 3.1.7.7 3.1-25 SLC System: flow path from pump into RPV E

SR 3.1.7.8 3.1-25 SLC System: piping from storage tank to pump suction is unblocked E

SR 3.1.7.9 3.1-26 SLC System: sodium pentaborate enrichment is within limits H

SR 3.1.8.3 3.1-29 SDV Vent and Drain Valves: response time and functional test A/ B SR 3.3.1.1.12 3.3-5 RPS: Reactor Mode Switch - Shutdown Position, Channel Functional A

Test SR 3.3.1.1.14 3.3-5 RPS: Logic System Functional Test C

l.a. IRM Neutron Flux - High 1.b. IRM Inoperable

3.

Reactor Vessel Steam Dome Pressure - High

4.

Reactor Vessel Water Level - Low, Level 3

5.

MSIV - Closure

6.

Drywell Pressure - High 7.a. SDV Water Level - High, RTD 7.b. SDV Water Level - High, Float Switch

8.

Turbine Stop Valve - Closure

9.

TCV Fast Closure, Trip Oil Pressure - Low

10.

Reactor Mode Switch - Shutdown Position

11.

Manual Scram SR 3.3.2.1.6 3.3-19 CRB: Reactor Mode Switch - Shutdown Position, Channel Functional A

Test SR 3.3.2.2.4 3.3-22 FW and Main Turbine High Water Level Trip: Logic Sys Functional C

T est_

SR 3.3.3.2.1 3.3-28 Backup Control System: control circuit and transfer switch A

SR 3.3.4.1.4 3.3-31 EOC-RPT: Logic System Functional Test C

SR 3.3.4.2.4 3.3-34 ATWS-RPT: Logic System Functional Test C

E1 -67

SURVEILLANCE I PAGE I DESCRIPTION l CATEGORY SR 3.3.5.1.6 3.3-41 ECCS: Logic System Functional Test 1.a. Reactor Vessel Water Level - Low Low Low, Level 1 1.b. Drywell Pressure - High 1.c. Reactor Steam Dome Pressure - Low (Injection Permissive and ECCS Initiation) 1.e. Core Spray Pump Start Time Delay Relay - Pumps A, B, C, D (Diesel & Normal power) 2.a. Reactor Vessel Water Level - Low Low Low, Level 1 2.b. Drywell Pressure - High 2.c. Reactor Steam Dome Pressure - Low (Injection Permissive and ECCS Initiation) 2.d. Reactor Steam Dome Pressure - Low (Recirc. Disch. Valve Permissive) 2.e. Reactor Vessel Water Level - Level 0 2.f.

LPCI Pump Start Time Delay Relay - Pumps A, B, C, D (Diesel &

Normal power) 3.a. Reactor Vessel Water Level - Low Low, Level 2 3.b. Drywell Pressure - High 3.c.

Reactor Vessel Water Level - High, Level 8 3.d. Condensate Header Level - Low 3.e. Suppression Pool Water Level - High 3.f.

HPCI Pump Discharge Flow - Low (Bypass) 4.a. Reactor Vessel Water Level - Low Low Low, Level 1 (Sys A) 4.b. Drywell Pressure - High (Sys A) 4.c. ADS Initiation Timer (Sys A) 4.d. Reactor Vessel Water Level - Low, Level 3 (Sys A) 4.e. Core Spray Pump Discharge Pressure - High (Sys A) 4.f.

LPCI Pump Discharge Pressure - High (Sys A) 4.g. ADS High Drywell Pressure Bypass Timer (Sys A) 5.a. Reactor Vessel Water Level - Low Low Low, Level 1 (Sys B) 5.b. Drywell Pressure - High (Sys B) 5.c. ADS Initiation Timer (Sys B) 5.d. Reactor Vessel Water Level - Low, Level 3 (Sys B) 5.e. Core Spray Pump Discharge Pressure - High (Sys B) 5.f.

LPCI Pump Discharge Pressure - High (Sys B) 5.g. ADS High Drywell Pressure Bypass Timer (Sys B)

C SR 3.3.5.2.4 3.3-50 RCIC System: Logic System Functional Test

1.

Reactor Vessel Water Level - Low Low, Level 2

2.

Reactor Vessel Water Level - High, Level 8 SR 3.3.6.1.6 3.3-57 Primary Containment Isolation: Logic System Functional Test 1.a. MSL Isolation: Reactor Vessel Water Level - Low Low Low, Level

_ _ _ _ _ _ _ _ _ _1 El-68

SURVEILLANCE I PAGE I

DESCRIPTION I CATEGORY 1.b. MSL Isolation: MSL Pressure - Low 1.c. MSL Isolation: MSL Flow - High 1.d. MSL Isolation: Main Steam Tunnel Temperature - High 2.a.

PC Isolation: Reactor Vessel Water Level - Low, Level 3 2.b.

PC Isolation: Drywell Pressure - High 3.a. HPCI Isolation: HPCI Steam Line Flow - High 3.b. HPCI Isolation: HPCI Steam Line Pressure - Low 3.c. HPCI Isolation: HPCI Turbine Exhaust Diaphragm Pressure -

High 3.d. HPCI Isolation: HPCI Steam Line Space HPCI Pump Room Area Temp. - High 3.e. HPCI Isolation: HPCI Steam Line Space Torus Area (Exit)

Temperature - High 3.f.

HPCI Isolation: HPCI Steam Line Space Torus Area (Midway)

Temperature - High 3.g. HPCI Isolation: HPCI Steam Line Space Torus Area (Entry)

Temperature - High 4.a. RCIC Isolation: RCIC Steam Line Flow - High 4.b. RCIC Isolation: RCIC Steam Supply Line Pressure - Low 4.c.

RCIC Isolation: RCIC Turbine Exhaust Diaphragm Pressure -

High 4.d.

RCIC Isolation: RCIC Steam Line Space RCIC Pump Room Area Temp. - High 4.e. RCIC Isolation: RCIC Steam Line Space Torus Area (Exit)

Temperature - High 4.f.

RCIC Isolation: RCIC Steam Line Space Torus Area (Midway)

Temperature - High 4.g. RCIC Isolation: RCIC Steam Line Space Torus Area (Entry)

Temperature - High 5.a. RWCU Isolation: Main Steam Valve Vault Area Temperature -

High 5.b. RWCU Isolation: Pipe Trench Area Temperature - High 5.c.

RWCU Isolation: Pump Room A Area Temperature - High 5.d. RWCU Isolation: Pump Room B Area Temperature - High 5.e. RWCU Isolation: Heat Exchanger Room Area (West Wall) Temp.

- High 5.f.

RWCU Isolation: Heat Exchanger Room Area (East Wall) Temp.

- High 5.g. RWCU Isolation: SLC System Initiation 5.h.

RWCU Isolation: Reactor Vessel Water Level - Low, Level 3 6.a. SDC Isolation: Reactor Steam Dome Pressure - High 6.b. SDC Isolation: Reactor Vessel Water Level - Low, Level 3 6.c. SDC Isolation: Drywell Pressure - High E1-69

SURVEILLANCE PAGE DESCRIPTION CATEGORY SR 3.3.6.2.4 3.3-63 Secondary Cont. Isolation: Logic System Functional Test C

1.

Reactor Vessel Water Level - Low, Level 3

2.

Drywell Pressure - High

3.

Reactor Zone Exhaust Radiation - High

4.

Refueling Floor Exhaust Radiation - High SR 3.3.7.1.6 3.3-68 CREV System: Logic System Functional Test C

1.

Reactor Vessel Water Level - Low, Level 3

2.

Drywell Pressure - High

3.

Reactor Zone Exhaust Radiation - High

4.

Refueling Floor Exhaust Radiation - High SR 3.3.8.2.3 3.3-77 RPS Electric Power Monitoring: system functional test D

SR 3.4.3.2 3.4-8 Safety / Relief Valves (S/RVs): manual actuation F

SR 3.5.1.8 3.5-6 ECCS-Operating: HPCI pump flow rate (Low pressure test)

E SR 3.5.1.9 3.5-6 ECCS-Operating: injection/spray subsystems, Automatic Actuation D

SR 3.5.1.10 3.5-7 ECCS-Operating: ADS, Automatic Actuation D

SR 3.5.1.11 3.5-7 ECCS-Operating: ADS valve manual actuation F

SR 3.5.1.12 3.5-7 ECCS-Operating: auto transfer of 480 V MOV Board power supply D

SR 3.5.2.5 3.5-11 ECCS-Shutdown: injection/spray subsystems, Automatic Actuation D

SR 3.5.3.4 3.5-13 RCIC System: pump flow rate (Low pressure test)

A SR 3.5.3.5 3.5-14 RCIC System: Automatic Actuation D

SR 3.6.1.1.2 3.6-2 Primary Containment: drywell to suppression chamber delta P, Leak G

Rate SR 3.6.1.3.7 3.6-16 PCIVs: Automatic Actuation D

SR 3.6.1.3.8 3.6-16 PCIVs: instrument line Excess Flow Check Valve, Automatic Actuation D

SR 3.6.1.3.9 3.6-16 PCIVs: TIP squib valves E

SR 3.6.1.6.3 3.6-23 Suppression Chamber-to-Drywell Vacuum Breakers: open setpoint E / F SR 3.7.5.2 3.7-17 Main Turbine Bypass System: Automatic Actuation D

SR 3.7.5.3 3.7-17 Main Turbine Bypass System: response time B

El -70

TABLE 2 INSTRUMENT CALIBRATION SURVEILLANCES SURVEILLANCE PAGE ITEM FUNCTION SYSTEM SR 3.3.1.1.13 3.3-5 2.a.

APRM Neutron Flux - High, Setdown RPS SR 3.3.1.1.13 3.3-5 2.b.

APRM Flow Biased Simulated Thermal Power - High RPS SR 3.3.1.1.13 3.3-5 2.c.

APRM Neutron Flux - High RPS SR 3.3.1.1.13 3.3-5

4.

Reactor Vessel Water Level - Low, Level 3 RPS SR 3.3.1.1.13 3.3-5

5.

MSIV - Closure RPS SR 3.3.1.1.13 3.3-5

6.

Drywell Pressure - High RPS SR 3.3.1.1.13 3.3-5 7.a.

SDV Water Level - High, RTD RPS SR 3.3.1.1.13 3.3-5 7.b.

SDV Water Level - High, Float Switch RPS SR 3.3.1.1.13 3.3-5

8.

Turbine Stop Valve - Closure RPS SR 3.3.1.1.13 3.3-5

9.

TCV Fast Closure, Trip Oil Pressure - Low RPS SR 3.3.1.1.15 3.3-5

8.

Turbine Stop Valve Closure Bypass Function RPS SR 3.3.1.1.15 3.3-5

9.

TCV Fast Closure, Trip Oil Pressure - Low Bypass Function RPS SR 3.3.2.1.4 3.3-18 l.a Rod Block Monitor Low Power Range - Upscale Control Rod Block SR 3.3.2.1.4 3.3-18 1.b Rod Block Monitor Intermediate Power Range - Upscale Control Rod Block SR 3.3.2.1.4 3.3-18 1.c Rod Block Monitor High Power Range - Upscale Control Rod Block SR 3.3.2.1.4 3.3-18 i.e Rod Block Monitor Downscale Control Rod Block SR 3.3.2.1.5 3.3-19

2.

Rod Worth Minimizer 10% RTP Bypass Function Control Rod Block SR 3.3.2.1.8 3.3-19 l.a Rod Block Monitor Low Power Range -- Upscale (Bypass)

Control Rod Block SR 3.3.2.1.8 3.3-19 1.b Rod Block Monitor Intermediate Power Range -- Upscale Control Rod Block (Bypass)

SR 3.3.2.1.8 3.3-19 1.c Rod Block Monitor High Power Range -- Upscale (Bypass)

Control Rod Block SR 3.3.2.2.3 3.3-22 FW and Main Turbine High Water Level Trip FW & Main Turbine SR 3.3.3.1.4 3.3-25 2.a.

Reactor Vessel Water Level - Emergency Systems Range PAM SR 3.3.3.1.4 3.3-25 2.b.

Reactor Vessel Water Level - Post Accident Flood Range PAM SR 3.3.3.1.4 3.3-25

3.

Suppression Pool Water Level PAM SR 3.3.3.1.4 3.3-25 4.a.

Drywell Pressure - Normal Range PAM SR 3.3.3.1.4 3.3-25 4.b.

Drywell Pressure - Wide Range PAM SR 3.3.3.1.4 3.3-25

5.

Primary Containment Area Radiation PAM SR 3.3.3.1.4 3.3-25

6.

PCIV Position PAM SR 3.3.3.1.4 3.3-25

8.

Suppression Pool Water Temperature PAM SR 3.3.3.1.4 3.3-25

9.

Drywell Atmosphere Temperature PAM SR 3.3.3.2.2 3.3-28 Suppression Pool Water Level Backup Control Sys El -71

SURVEILLANCE PAGE ITEM FUNCTION SYSTEM SR 3.3.3.2.3 3.3-28 Each required inst. channel except Supp. Pool Water Level Backup Control Sys (see Bases, Table B 3.3.3.2-1)

1.

Reactor Water Level Indication

2.

Reactor Pressure Indication

3.

Suppression Pool Temperature Indication

4.

Suppression Pool Level Indication (see SR 3.3.3.2.2)

5.

Drywell Pressure Indication

6.

RHR Flow Indication

7.

RCIC Flow Indication

8.

RCIC Turbine Speed Indication

9.

Drywell Temperature Indicator

10.

RHRSW Header Pressure SR 3.3.4.1.2 3.3-31 Turbine Stop Valve and TCV Closure Bypass Function EOC-RPT (covered by SR 3.3.1.1.1 5, items 8 & 9 above)

SR 3.3.4.1.3 3.3-31 Turbine Stop Valve - Closure (RPS item 8 Inst.)

EOC-RPT SR 3.3.4.1.3 3.3-31 TCV Fast Closure, Trip Oil Press. - Low (RPS item 9 Inst.)

EOC-RPT SR 3.3.4.2.3 3.3-34

a.

Reactor Vessel Water Level - Low Low, Level 2 ATWS-RPT SR 3.3.4.2.3 3.3-34

b.

Reactor Steam Dome Pressure - High ATWS-RPT SR 3.3.5.1.5 3.3-41 l.a.

Reactor Vessel Water Level - Low Low Low, Level 1 ECCS: Core Spray SR 3.3.5.1.5 3.3-41 1.b.

Drywell Pressure - High ECCS: Core Spray SR 3.3.5.1.5 3.3-41 1.d.

Core Spray Pump Discharge Flow - Low (Bypass)

ECCS: Core Spray SR 3.3.5.1.5 3.3-41 I.e.

Core Spray Pump Start Time Delay Relay:

ECCS: Core Spray

- Pumps A, B, C, D (with diesel power)

SR 3.3.5.1.5 3.3-41 i.e.

- Pump A (with normal power)

ECCS: Core Spray SR 3.3.5.1.5 3.3-41 i.e.

- Pump B (with normal power)

ECCS: Core Spray SR 3.3.5.1.5 3.3-41 i.e.

- Pump C (with normal power)

ECCS: Core Spray SR 3.3.5.1.5 3.3-41 i.e.

- Pump D (with normal power)

ECCS: Core Spray SR 3.3.5.1.5 3.3-41 2.a.

Reactor Vessel Water Level - Low Low Low, Level 1 ECCS: LPCI SR 3.3.5.1.5 3.3-41 2.b.

Drywell Pressure - High ECCS: LPCI SR 3.3.5.1.5 3.3-41 2.e.

Reactor Vessel Water Level - Level 0 ECCS: LPCI SR 3.3.5.1.5 3.3-41 2.f.

LPCI Pump Start Time Delay Relay:

ECCS: LPCI

- Pumps A, B, C, D (with diesel power)

SR 3.3.5.1.5 3.3-41 2.f.

- Pump A (with normal power)

ECCS: LPCI SR 3.3.5.1.5 3.3-41 2.f.

- Pump B (with normal power)

ECCS: LPCI SR 3.3.5.1.5 3.3-41 2.f.

- Pump C (with normal power)

ECCS: LPCI SR 3.3.5.1.5 3.3-41 2.f.

- Pump D (with normal power)

ECCS: LPCI SR 3.3.5.1.5 3.3-41 3.a.

Reactor Vessel Water Level - Low Low, Level 2 ECCS: HPCI SR 3.3.5.1.5 3.3-41 3.b.

Drywell Pressure - High ECCS: HPCI E1 -72

SURVEILLANCE PAGE ITEM FUNCTION SYSTEM SR 3.3.5.1.5 3.3-41 3.c.

Reactor Vessel Water Level - High, Level 8 ECCS: HPCI SR 3.3.5.1.5 3.3-41 3.f.

HPCI Pump Discharge Flow - Low (Bypass)

ECCS: HPCI SR 3.3.5.1.5 3.3-41 4.a.

Reactor Vessel Water Level - Low Low Low, Level 1 ECCS: ADS-A SR 3.3.5.1.5 3.3-41 4.b.

Drywell Pressure - High ECCS: ADS-A SR 3.3.5.1.5 3.3-41 4.c.

ADS Initiation Timer ECCS: ADS-A SR 3.3.5.1.5 3.3-41 4.d.

Reactor Vessel Water Level - Low, Level 3 (Confirmatory)

ECCS: ADS-A SR 3.3.5.1.5 3.3-41 4.g.

ADS High Drywell Pressure Bypass Timer ECCS: ADS-A SR 3.3.5.1.5 3.3-41 5.a.

Reactor Vessel Water Level - Low Low Low, Level 1 ECCS: ADS-B SR 3.3.5.1.5 3.3-41 5.b.

Drywell Pressure - High ECCS: ADS-B SR 3.3.5.1.5 3.3-41 5.c.

ADS Initiation Timer ECCS: ADS-B SR 3.3.5.1.5 3.3-41 5.d.

Reactor Vessel Water Level - Low, Level 3 (Confirmatory)

ECCS: ADS-B SR 3.3.5.1.5 3.3-41 5.g.

ADS High Drywell Pressure Bypass Timer ECCS: ADS-B SR 3.3.5.2.3 3.3-50

1.

Reactor Vessel Water Level - Low Low, Level 2 RCIC SR 3.3.5.2.3 3.3-50

2.

Reactor Vessel Water Level - High, Level 8 RCIC SR 3.3.6.1.5 3.3-57 l.a.

MSL Isolation: Reactor Vessel Water Level - Low Low Low, Primary Level 1 Containment SR 3.3.6.1.5 3.3-57 1.b.

MSL Isolation: MSL Pressure - Low Primary Containment SR 3.3.6.1.5 3.3-57 1.c.

MSL Isolation: MSL Flow - High Primary Containment SR 3.3.6.1.5 3.3-57 1.d.

MSL Isolation: Main Steam Tunnel Temperature - High Primary Containment SR 3.3.6.1.5 3.3-57 2.a.

PC Isolation: Reactor Vessel Water Level - Low, Level 3 Primary Containment SR 3.3.6.1.5 3.3-57 2.b.

PC Isolation: Drywell Pressure - High Primary Containment SR 3.3.6.1.5 3.3-57 3.a.

HPCI Isolation: HPCI Steam Line Flow - High Primary Containment SR 3.3.6.1.5 3.3-57 3.b.

HPCI Isolation: HPCI Steam Supply Line Pressure - Low Primary Containment SR 3.3.6.1.5 3.3-57 3.c.

HPCI Isolation: HPCI Turbine Exhaust Diaphragm Pressure Primary

- High Containment SR 3.3.6.1.5 3.3-57 4.a.

RCIC Isolation: RCIC Steam Line Flow - High Primary Containment SR 3.3.6.1.5 3.3-57 4.b.

RCIC Isolation: RCIC Steam Supply Line Pressure - Low Primary Containment SR 3.3.6.1.5 3.3-57 4.c.

RCIC Isolation: RCIC Turbine Exhaust Diaphragm Pressure Primary

- High Containment SR 3.3.6.1.5 3.3-57 5.a RWCU Isolation: Main Steam Valve Vault Area Primary Temperature-High Containment El -73

SURVEILLANCE PAGE ITEM FUNCTION SYSTEM SR 3.3.6.1.5 3.3-57 5.h.

RWCU Isolation: Reactor Vessel Water Level - Low, Level Primary 3

Containment SR 3.3.6.1.5 3.3-57 6.a.

SDC Isolation: Reactor Steam Dome Pressure - High Primary Containment SR 3.3.6.1.5 3.3-57 6.b.

SDC Isolation: Reactor Vessel Water Level - Low, Level 3 Primary Containment SR 3.3.6.1.5 3.3-57 6.c.

SDC Isolation: Drywell Pressure - High Primary Containment SR 3.3.6.2.3 3.3-63

1.

Reactor Vessel Water Level - Low, Level 3 Secondary Containment SR 3.3.6.2.3 3.3-63

2.

Drywell Pressure - High Secondary Containment SR 3.3.6.2.3 3.3-63

3.

Reactor Zone Exhaust Radiation - High Secondary Containment SR 3.3.6.2.3

• 3.3-63 4.

Refueling Floor Exhaust Radiation - High Secondary Containment SR 3.3.7.1.5 3.3-68

1.

Reactor Vessel Water Level - Low, Level 3 CREV SR 3.3.7.1.5 3.3-68

2.

Drywell Pressure - High CREV SR 3.3.7.1.5 3.3-68

3.

Reactor Zone Exhaust Radiation - High CREV SR 3.3.7.1.5 3.3-68

4.

Refueling Floor Exhaust Radiation - High CREV SR 3.4.5.4 3.4-14 Required leakage detection system instrumentation RCS Leak Detection SR 3.6.1.5.3 3.6-21 Reactor Bldg-to-Suppression Chamber Vacuum Breakers:

Primary open setpoint Containment El -74

FIGURE 1 INSTRUMENT VALUE RELATIONSHIPS AL (upper)

Av (max)

Av (min)

Setpoint (SP)

Av (min)

Av (max)

AL (lower)

El-75

ATTACHMENT 1 DETAILED COMPONENT LEVEL ASSESSMENT OF BROWNS FERRY UNIT 1 SURVEILLANCE INTERVAL EXTENSIONS FOR NON-INSTRUMENT CALIBRATION SURVEILLANCE REQUIREMENTS SYSTEM/COMPONENT SURVEILLANCE:

Standby Liquid Control System (SLCS)

TECH SPEC NO:

PAGE NO:

SR 3.1.7.6 3.1-25 SR 3.1.7.7 3.1-25 SR 3.1.7.8 3.1-25 TYPE OF SURVEILLANCE:

Functional Test PURPOSE:

Verification of an adequate pump flow rate and a fully functional flow path from the storage tank to the reactor vessel.

SAFETY FUNCTION:

Bring the reactor from full power to cold, xenon-free subcritical conditions at the most reactive point in the fuel cycle with no credit for control rods.

FSAR EVENT TYPE:

The SLCS is not assumed to function in any DBA or transient and is not the primary success path of a safety sequence analysis.

It is a reactivity backup to the control rods and is included when analyzing Anticipated Transients Without Scram (ATWS). ATWS is considered a special event and is outside the plant design basis.

El-Al

EFFECT ON PLANT SAFETY:

No measurable effect:

• The available volume of sodium pentaborate (SPB) is verified at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Weight of available Boron-10 is verified monthly.

• The concentration of SPB is verified monthly and within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if water or SPB is added to the solution.

• The continuity of the explosive charge is verified monthly.

• Flow path restriction due to precipitation of SPB from the solution is precluded by the frequent checks on concentration.

SURVEILLANCE CATEGORY:

E El -A2

SYSTEM/COMPONENT SURVEILLANCE:

Standby Liquid Control System (SLCS)

TECH SPEC NO:

PAGE NO:

SR 3.1.7.9 3.1-26 TYPE OF SURVEILLANCE:

Inspection PURPOSE:

Verify adequate Boron enrichment by analysis of a sample of the sodium pentaborate solution.

SAFETY FUNCTION:

Bring the reactor from full power to cold, xenon free subcritical conditions at the most reactive point in the fuel cycle with no credit for control rods.

FSAR EVENT TYPE:

The SLCS is not assumed to function in any Design Bases Accident or transient and is not the primary success path of a safety sequence analysis.

It is a reactivity backup to the control rods and is included when analyzing the Anticipated Transient Without Scram (ATWS).

ATWS is considered a special event and is outside the plant design basis.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Monitoring the sodium pentaborate parameters on at least a monthly basis ensures adequate enrichment is maintained.

• The enrichment analysis is repeated after any additions are made to the SLCS storage tank.

SURVEILLANCE CATEGORY:

H El -A3

SYSTEM/COMPONENT SURVEILLANCE:

Scram Discharge Volume (SDV) Vent and Drain Valves TECH SPEC NO:

PAGE NO:

SR 3.1.8.3 3.1-29 TYPE OF SURVEILLANCE:

Functional and Response Time Test PURPOSE:

Demonstrate that the SDV vent and drain valves actuate as specified and within the required response time.

SAFETY FUNCTION:

The SDV vent and drain valves are not required to function to mitigate a Design Bases Accident or transient.

These valves are not considered part of the reactor coolant pressure boundary ("Generic Safety Evaluation Report Regarding integrity of BWR Scram System Piping", NUREG-0803, August 1981).

The SDV vent and drain valves are normally open during reactor operation such that leakage into the SDV will drain.

The valves will close on a scram signal.

FSAR EVENT TYPE:

Not part of primary design basis success path for reactor shutdown.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Actuation of these valves occurs during reactor startup and shutdown.

• Predominate valve failure modes would be detected during these actuations.

SURVEILLANCE CATEGORY:

A / B El -A4

SYSTEM/COMPONENT SURVEILLANCE:

Reactor Mode Switch -

Shutdown Position TECH SPEC NO:

PAGE NO:

SR 3.3.1.1.12 3.3-5 TYPE OF SURVEILLANCE:

Functional Test PURPOSE:

Ensure reactor mode switch operates in the shutdown position.

SAFETY FUNCTION:

Selection of shutdown mode for the RPS logic causes the reactor to scram and other selected functions to be bypassed.

FSAR EVENT TYPE:

Not part of the primary success path.

Safety analysis is based on automatic scram functions.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Not critical to reactor shutdown function.

• Low switch failure rate.

• Contribution of switch failure in RPS logic is negligible.

• Redundant manual scram function is provided.

SURVEILLANCE CATEGORY:

A El -A5

SYSTEM/COMPONENT SURVEILLANCE:

Reactor Protection System (RPS) Instrumentation TECH SPEC NO:

PAGE NO:

SR 3.3.1.1.14 3.3-5 TYPE OF SURVEILLANCE:

Logic System Functional Test PURPOSE:

Verify the capability of individual instrumentation channels in association with the RPS logic to provide the designed scram functions.

SAFETY FUNCTION:

Initiate scram signal when measured plant parameters exceed specified limits.

FSAR EVENT TYPE:

Reactivity Control EFFECT ON PLANT SAFETY:

No measurable effect:

• The RPS logic is one-out-of-two-twice.

• Diverse scram signals (flux, pressure, water level, and position switch) will respond to transient events.

• Individual channel checks (daily) and channel functional tests (at least quarterly) preserve the integrity of the RPS instrumentation.

Significant component failures are detected by these supplementary tests.

SURVEILLANCE CATEGORY:

C El -A6

SYSTEM/COMPONENT SURVEILLANCE:

Reactor Mode Switch -

Shutdown Position TECH SPEC NO:

PAGE NO:

SR 3.3.2.1.6 3.3-19 TYPE OF SURVEILLANCE:

Functional test PURPOSE:

Verify control rod withdrawal is prevented by reactor Mode Switch in the Shutdown position.

SAFETY FUNCTION:

Ensures no control rod withdrawal when operating in the Shutdown Mode.

FSAR EVENT TYPE:

Reactivity Control.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Not a function of fuel cycle extension.

• Test conducted normally during plant shutdown.

SURVEILLANCE CATEGORY:

A El -A7

SYSTEM/COMPONENT SURVEILLANCE:

Feedwater and Main Turbine High Water Level Trip Instrumentation TECH SPEC NO:

PAGE NO:

SR 3.3.2.2.4 3.3-22 TYPE OF SURVEILLANCE:

Logic System Functional Test PURPOSE:

Demonstrate that the instrumentation channels and associated logic will provide a feedwater pump trip and main turbine trip, including closure of the main turbine valves.

SAFETY FUNCTION:

Respond to feedwater control system failure (maximum demand) to prevent excess water carryover to the main turbine.

Also, to preserve operating limits (e.g., MCPR, MAPLHGR).

FSAR EVENT TYPE:

Decrease in core coolant temperature.

Excess water carryover.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant trip systems.

• Channel functional tests are conducted quarterly which would identify individual component failures.

SURVEILLANCE CATEGORY:

C El -A8

SYSTEM/COMPONENT SURVEILLANCE:

Backup Control System TECH SPEC NO:

PAGE NO:

SR 3.3.3.2.1 3.3-28 TYPE OF SURVEILLANCE:

Functional Test PURPOSE:

Verification of each control circuit and transfer switch function.

SAFETY FUNCTION:

Allow reactor to be shutdown in a controlled manner when access to main control room is unavailable.

FSAR EVENT TYPE:

Not an Engineered Safety Feature required to respond to any DBA or transient considered in the safety analysis.

Function is only required in response to a situation calling for evacuation of the main control room.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Not part of the primary success path for reactor shutdown.

• Incorrect positioning of the transfer switches can be detected during plant operation and corrected.

SURVEILLANCE CATEGORY:

A E1-A9

SYSTEM/COMPONENT SURVEILLANCE:

End of Cycle Recirculation Pump Trip (EOC-RPT)

Instrumentation TECH SPEC NO:

PAGE NO:

SR 3.3.4.1.4 3.3-31 TYPE OF SURVEILLANCE:

Logic System Functional Test PURPOSE:

Verify the capability of individual instrumentation channels, in association with the EOC-RPT logic, to provide the designed trip function.

SAFETY FUNCTION:

Initiate a recirculation pump trip when a main turbine trip or generator load rejection occurs when reactor THERMAL POWER is > 30% RTP.

FSAR EVENT TYPE:

Reactivity Control.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant channels exist to initiate recirculation pump trip.

• Channel Functional Tests which are conducted quarterly would detect significant failures of the EOC-RPT instrumentation.

SURVEILLANCE CATEGORY:

C El -A1 0

SYSTEM/COMPONENT SURVEILLANCE:

ATWS Recirculation Pump Trip (ATWS-RPT) Instrumentation TECH SPEC NO:

PAGE NO:

SR 3.3.4.2.4 3.3-34 TYPE OF SURVEILLANCE:

Logic System Functional Test PURPOSE:

Verify the capability of individual instrumentation channels, in association with the ATWS-RPT logic, to provide the designed trip function.

SAFETY FUNCTION:

Provides backup reactivity control by tripping the recirculation pumps on reactor vessel low water level or high reactor dome pressure.

FSAR EVENT TYPE:

Is not part of the primary design basis success path.

Included when analyzing Anticipated Transients Without Scram (a special event).

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant channels exist to initiate recirculation pump trip.

• Channel Functional Tests which are conducted quarterly would detect significant failures of the ATWS-RPT instrumentation.

SURVEILLANCE CATEGORY:

C El-All

SYSTEM/COMPONENT SURVEILLANCE:

Emergency Core Cooling System (ECCS) Instrumentation TECH SPEC NO:

PAGE NO:

SR 3.3.5.1.6 3.3-41 TYPE OF SURVEILLANCE:

Logic System Functional Test PURPOSE:

Verify the capability of individual instrumentation channels, in association with the ECCS logic, to provide the designed initiation functions.

SAFETY FUNCTION:

Initiate ECCS on loss of coolant inventory.

FSAR EVENT TYPE:

Decrease in reactor coolant inventory.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant instrumentation channels exist to initiate the ECCS subsystems.

• Individual channel checks (daily) and channel functional tests (at least quarterly) preserve the integrity of the ECCS instrumentation.

Significant component failures are detected by these supplementary tests.

SURVEILLANCE CATEGORY:

C E1-A12

SYSTEM/COMPONENT SURVEILLANCE:

Reactor Core Isolation Cooling (RCIC) System Instrumentation TECH SPEC NO:

PAGE NO:

SR 3.3.5.2.4 3.3-50 TYPE OF SURVEILLANCE:

Logic System Functional Test PURPOSE:

Verify the capability of individual instrumentation channels, in association with the RCIC logic, to provide the designed initiation and isolation functions.

SAFETY FUNCTION:

Restores coolant inventory loss following isolation of the reactor from the primary heat sink.

Also provides high pressure source of coolant inventory makeup.

FSAR EVENT TYPE:

Not part of the primary success path for design basis events.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant instrumentation channels exist to initiate or isolate the RCIC system.

• Individual channel checks (daily) and channel functional tests (at least quarterly) preserve the integrity of the RCIC instrumentation.

Significant component failures are detected by these supplementary tests.

SURVEILLANCE CATEGORY:

C El -A1 3

SYSTEM/COMPONENT SURVEILLANCE:

Primary Containment Isolation (PCI) Instrumentation TECH SPEC NO:

PAGE NO:

SR 3.3.6.1.6 3.3-57 TYPE OF SURVEILLANCE:

Logic System Functional Test PURPOSE:

Verifies the capability of individual instrumentation channels, in association with the PCI logic, to provide the designed isolation functions.

SAFETY FUNCTION:

Provides trip signals to PCI valves when specified plant parameters exceed design limits.

FSAR EVENT TYPE:

Radioactive release basis during and following design basis events.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant inboard/outboard isolation valves with diverse power sources.

• Redundant and diverse trip signals for major transient events.

• Individual channel checks (daily) and channel functional tests (at least quarterly) preserve the integrity of the PCI instrumentation.

Significant component failures are detected by these supplementary tests.

SURVEILLANCE CATEGORY:

C E1-A14

SYSTEM/COMPONENT SURVEILLANCE:

Secondary Containment Isolation (SCI) Instrumentation TECH SPEC NO:

PAGE NO:

SR 3.3.6.2.4 3.3-63 TYPE OF SURVEILLANCE:

Logic System Functional Test PURPOSE:

Verify the capability of individual instrumentation channels, in association with the SCI logic, to provide the designed isolation functions.

SAFETY FUNCTION:

Provide trip signals to SCI valves and for initiation of the Standby Gas Treatment System when specified plant parameters exceed design limits.

FSAR EVENT TYPE:

Radioactive release basis during and following design basis events.

Containment during operational events when primary containment is not required.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant isolation valves provided.

• Individual channel checks (daily) and channel functional tests (at least quarterly) preserve the integrity of the SCI instrumentation.

Significant component failures are detected by these supplementary tests.

• Logic System Functional Tests of radiation instrument channels are conducted at least once every six months.

SURVEILLANCE CATEGORY:

C El-A15

SYSTEM/COMPONENT SURVEILLANCE:

Control Room Emergency Ventilation (CREV) System Instrumentation TECH SPEC NO:

PAGE NO:

SR 3.3.7.1.6 3.3-68 TYPE OF SURVEILLANCE:

Logic System Functional Test PURPOSE:

Verify the capability of individual instrumentation channels, in association with the CREV logic, to provide the designed initiation of the CREV system.

SAFETY FUNCTION:

To ensure habitability of the control room under all plant operating conditions.

FSAR EVENT TYPE:

Radioactive release design basis.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Two redundant CREV systems are available for the design function.

• Individual channel checks (daily) and channel functional tests (at least quarterly) preserve the integrity of the CREV instrumentation.

Significant component failures are detected by these supplementary tests.

• Control room air supply duct radiation monitors have logic system functional tests conducted at least once every six months.

SURVEILLANCE CATEGORY:

C El-A16

SYSTEM/COMPONENT SURVEILLANCE:

RPS Electric Power Monitoring (RPS-EPM)

TECH SPEC NO:

PAGE NO:

SR 3.3.8.2.3 3.3-77 TYPE OF SURVEILLANCE:

Simulated Automatic Actuation Test PURPOSE:

Demonstrate capability of the RPS-EPM system to automatically open the associated contractors in response to a system voltage or frequency signal which exceeds established limits.

SAFETY FUNCTION:

Preserve the integrity of the equipment comprising the electrical load of the RPS-MG set, with regard to over-voltage, under-voltage, or under-frequency.

FSAR EVENT TYPE:

Primarily reactivity control.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant protective channels provided.

• Additional channel functional tests are performed at least once every six months.

SURVEILLANCE CATEGORY:

D El -A1 7

SYSTEM/COMPONENT SURVEILLANCE:

Manual Operation of Main Steam Relief Valves and Designated ADS Valves TECH SPEC NO:

PAGE NO:

SR 3.4.3.2 3.4-8 SR 3.5.1.11 3.5-7 TYPE OF SURVEILLANCE:

Functional Test PURPOSE:

Demonstrate capability of each Main Steam Relief Valve and ADS valve to open and provide an adequate flow path.

SAFETY FUNCTION:

Mitigate the consequences of DBA LOCAs and transients.

FSAR EVENT TYPE:

Reactor vessel overpressure protection.

Decrease in reactor coolant inventory (ADS).

EFFECT ON PLANT SAFETY:

No measurable effect:

• Analysis at the current Unit 1 licensed thermal power limit of 3,293 megawatts shows that the 1375 psig code limit for overpressure would be preserved with fewer than the available Main Steam Relief Valves coincident with failure of the primary scram function.

• Any four of the designated six ADS valves are sufficient to provide an adequate margin for depressurization.

• Two coolant injection systems (HPCI and RCIC) are available (in lieu of ADS in combination with LPCI and Core Spray) to maintain coolant inventory with the reactor coolant system still pressurized during a design basis event.

SURVEILLANCE CATEGORY:

F El -A1 8

SYSTEM/COMPONENT SURVEILLANCE:

High Pressure Coolant Injection (HPCI) System TECH SPEC NO:

PAGE NO:

SR 3.5.1.8 3.5-6 TYPE OF SURVEILLANCE:

Functional Test PURPOSE:

Demonstrate HPCI system capability to develop required flow at a low reactor pressure condition.

SAFETY FUNCTION:

Provide make-up for loss of coolant inventory.

FSAR EVENT TYPE:

Decrease in reactor coolant inventory.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Several alternate water injection sources are available for reactor low pressure conditions.

• Restriction of the flow path would be detected during the HPCI pump flow test at high pressure which is performed at least once per 92 days (quarterly).

• The quarterly high pressure test also demonstrates operability of the HPCI at the system level.

SURVEILLANCE CATEGORY:

E E1 -A1 9

SYSTEM/COMPONENT SURVEILLANCE:

Emergency Core Cooling Systems (ECCS)

TECH SPEC NO:

PAGE NO:

SR 3.5.1.9 3.5-6 SR 3.5.1.10 3.5-7 SR 3.5.2.5 3.5-11 TYPE OF SURVEILLANCE:

Simulated Automatic Actuation Test PURPOSE:

Demonstrate the capability of the ECCS to initiate in response to an actual or simulated automatic initiation signal.

SAFETY FUNCTION:

Mitigate the consequences of DBA LOCAs.

FSAR EVENT TYPE:

Decrease in reactor coolant inventory.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant instrumentation channels to provide actuation.

• Redundant water injection systems available.

• Individual channel checks (daily) and channel functional tests (at least quarterly) preserve the integrity of the ECCS instrumentation.

Significant component failures are detected by these supplementary tests.

SURVEILLANCE CATEGORY:

D E1-A20

SYSTEM/COMPONENT SURVEILLANCE:

480 Volt Reactor MOV Boards (ECCS)

TECH SPEC NO:

PAGE NO:

SR 3.5.1.12 3.5-7 TYPE OF SURVEILLANCE:

Simulated Automatic Actuation Test PURPOSE:

Demonstrate the capability to automatically transfer the power supply from the normal source to the alternate source for the MOV Board supplying power to the LPCI subsystem inboard injection valve and recirculation pump discharge valve.

SAFETY FUNCTION:

To ensure availability of a 480 Volt power supply to the LPCI inboard injection valve and the recirculation pump discharge valve actuators in the event that the power is lost to one of the 4kV Shutdown Boards.

FSAR EVENT TYPE:

Decrease in reactor coolant inventory.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant power supplies available to the 4kV Shutdown Boards.

• Availability of normal power supplies to the 4kV Shutdown Boards is verified at least once every seven days.

SURVEILLANCE CATEGORY:

D El -A21

SYSTEM/COMPONENT SURVEILLANCE:

Reactor Core Isolation Cooling (RCIC) System TECH SPEC NO:

PAGE NO:

SR 3.5.3.4 3.5-13 TYPE OF SURVEILLANCE:

Functional Test PURPOSE:

Demonstrate RCIC system capability to develop required flow at a low reactor pressure condition.

SAFETY FUNCTION:

Provide make-up for loss of coolant inventory associated with isolation transients.

Redundant high pressure water source to HPCI for certain events other than design basis.

FSAR EVENT TYPE:

Not part of the primary success path, particularly under low reactor pressure conditions.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Several alternate water injection sources are available for low reactor pressure conditions.

• Restriction of the flow path would be detected during the RCIC pump flow test at high pressure which is performed at least once every 92 days (quarterly).

• The quarterly high pressure test also demonstrates operability of the RCIC at the system level.

SURVEILLANCE CATEGORY:

A El -A22

SYSTEM/COMPONENT SURVEILLANCE:

Reactor Core Isolation Cooling (RCIC) System TECH SPEC NO:

PAGE NO:

SR 3.5.3.5 3.5-14 TYPE OF SURVEILLANCE:

Simulated Automatic Actuation Test PURPOSE:

Demonstrate the capability of the RCIC system to initiate in response to an actual or simulated automatic initiation signal.

SAFETY FUNCTION:

Provide make-up for loss of coolant inventory associated with isolation transients.

Redundant high pressure water source to HPCI for certain events other than design basis.

FSAR EVENT TYPE:

Not part of the primary success path for any design basis event.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Backup by HPCI for RCIC system functions.

• Redundant instrument channels provide actuation.

• Individual channel checks (daily) and channel functional tests (at least quarterly) preserve the integrity of the RCIC instrumentation.

Significant component failures are detected by these supplementary tests.

SURVEILLANCE CATEGORY:

D E1-A23

SYSTEM/COMPONENT SURVEILLANCE:

Drywell to Suppression Chamber TECH SPEC NO:

PAGE NO:

SR 3.6.1.1.2 3.6-2 TYPE OF SURVEILLANCE:

Leak Rate Test PURPOSE:

To verify that leakage from the drywell to the suppression chamber is maintained within allowable limits.

SAFETY FUNCTION:

Ensures that the suppression chamber condensing capability is maintained such that overpressurization of the primary containment does not occur.

FSAR EVENT TYPE:

Radioactive release design basis.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Reliability is not affected by increase in testing interval because the testing plan is self correcting if failure occurs.

• If a test fails to meet a specified limit, the test schedule for subsequent tests is required to be reviewed.

SURVEILLANCE CATEGORY:

G E1 -A24

SYSTEM/COMPONENT SURVEILLANCE:

Primary Containment Isolation Valves (PCIVs)

TECH SPEC NO:

PAGE NO:

SR 3.6.1.3.7 3.6-17 TYPE OF SURVEILLANCE:

Simulated Automatic Actuation Tests PURPOSE:

Demonstrate the capability of each PCIV to actuate to the isolation position on an actual or simulated isolation signal.

SAFETY FUNCTION:

Maintains potential radioactive releases within limits.

FSAR EVENT TYPE:

Radioactive release design basis.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant inboard/outboard isolation valves are provided.

• PCIVs are tested following maintenance, repair or replacement.

• The Inservice Testing Program, based on the ASME Boiler and Pressure Vessel Code,Section XI, results in additional and more frequent testing of the PCIVs.

SURVEILLANCE CATEGORY:

D E1 -A25

SYSTEM/COMPONENT SURVEILLANCE:

Excess Flow Check Valves (EFCVs)

TECH SPEC NO:

PAGE NO:

SR 3.6.1.3.8 3.6-16 TYPE OF SURVEILLANCE:

Simulated Automatic Actuation Tests.

PURPOSE:

Demonstrate the capability of each EFCV to actuate to the isolation position on an actual or simulated instrument line break signal.

SAFETY FUNCTION:

Maintain potential radioactive releases within limits.

FSAR EVENT TYPE:

Radioactive release design basis.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Low probability of instrument line break coincident with failure of EFCV would result in only a small break.

• Manual closure of an upstream isolation valve is available in the event of EFCV failure.

SURVEILLANCE CATEGORY:

D E1-A26

SYSTEM/COMPONENT SURVEILLANCE:

Traversing Incore Probe (TIP) Squib Valves TECH SPEC NO:

PAGE NO:

SR 3.6.1.3.9 3.6-16 TYPE OF SURVEILLANCE:

Functional Test PURPOSE:

Provide assurance of the operability of the TIP shear isolation valves which are actuated by an explosive squib charge.

SAFETY FUNCTION:

Maintain potential radioactive releases within limits by isolating the TIP system on containment isolation signal.

FSAR EVENT TYPE:

Radioactive release design basis.

EFFECT ON PLANT SAFETY:

No. measurable effect:

• Explosive squib charge is removed, fired and replaced by a squib from the same batch or another batch containing a squib that has been successfully tested.

• Redundant inboard/outboard isolation valves are provided.

• Continuity checks of explosive squib charge are performed monthly.

• TIP system is only used infrequently (e.g., LPRM calibration).

• Shelf and operating life of explosive squib charge are not exceeded by the extended test interval.

SURVEILLANCE CATEGORY:

E El -A27

SYSTEM/COMPONENT SURVEILLANCE:

Suppression Chamber-to-Drywell Vacuum Breakers TECH SPEC NO:

PAGE NO:

SR 3.6.1.6.3 3.6-23 TYPE OF SURVEILLANCE:

Functional Test PURPOSE:

Verify that the vacuum breaker will open, and that the required force for opening is within the limit assumed in the safety analysis.

SAFETY FUNCTION:

Preserve the containment integrity by relieving drywell vacuum when the drywell atmosphere is depressurized below suppression chamber pressure.

FSAR EVENT TYPE:

Decrease in reactor coolant inventory (LOCA), inadvertent drywell spray actuation, cooling cycles, etc.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Redundant reactor suppression chamber-to-drywell vacuum breakers.

• Additional, more frequent functional tests of the vacuum breakers are performed in accordance with the Inservice Testing Program.

SURVEILLANCE CATEGORY:

E / F E1 -A28

SYSTEM/COMPONENT SURVEILLANCE:

Main Turbine Bypass System TECH SPEC NO:

PAGE NO:

SR 3.7.5.2 3.7-17 SR 3.7.5.3 3.7-17 TYPE OF SURVEILLANCE:

Simulated Automatic Actuation/Response Time Test PURPOSE:

Demonstrate that the Main Turbine Bypass valves actuate to their required positions on an actual or simulated initiation signal, and that valve movement occurs within the specified time limits.

SAFETY FUNCTION:

The Main Turbine Bypass system is a part of the primary success path which functions to mitigate the consequences of a feedwater controller failure (maximum demand), generator load rejection, or turbine trip event.

FSAR EVENT TYPE:

Increase in reactor pressure.

EFFECT ON PLANT SAFETY:

No measurable effect:

• Industry reliability studies for Boiling Water Reactors (BWRs), prepared by the BWR Owners Group (GE topical report NEDC-30936P-A) show that the overall safety systems' reliabilities are not dominated by the reliabilities of the logic systems, but by that of the mechanical components, (e.g., pumps and valves), which are consequently tested on a more frequent basis.

• Each Main Turbine Bypass valve is cycled through one cycle of full travel at least once per 31 days.

SURVEILLANCE CATEGORY:

D / B E1-A29

ENCLOSURE 2 TECHNICAL SPECIFICATION CHANGE (TS-433) 24 MONTH FUEL CYCLE PROPOSED TECHNICAL SPECIFICATION CHANGES (MARK-UP)

I.

AFFECTED PAGE LIST Unit 1 3.1-25 3.1-26 3.1-29 3.3-5*

3.3-18*

3.3-19*

3.3-22 3.3-25 3.3-28 3.3-31 3.3-34 3.3-41 3.3-50 3 3.3-57**

Unit 1 Unit 1 3.3-59**

3.6-21 3.3-60**

3.6-23 3.3-63 3.3-68 3.3-77 3.4-8 3.4-14 3.5-6 3.5-7 3.5-11 3.5-13 3.5-14 3.6-2 3.6-16 3.7-17 II.

REVISED PAGES See attached.

Assumes changes from proposed Technical Specification 430 have been approved.

Assumes changes from proposed Technical Specification 447 have been approved.

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.1.7.5 Verify the SLC conditions satisfy the following equation:

31 days AND Once within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after

(

C

)(

of F

(13 wt. %)(86 gpmX19.8 atom%)

where, C = sodium pentaborate solution concentration (weight percent)

Q = pump flow rate (gpm)

E = Boron-10 enrichment (atom percent Boron-1 0) water or boron is added to the solution

, Deleted: 18

]

Deleted:18

,24 _months on a-, I STAGGERED TEST BASIS SR 3.1.7.6 Verify each pump develops a flow rate 2 39 gpm at a discharge pressure 2 1275 psig.

SR 3.1.7.7 Verify flow through one SLC subsystem from pump into reactor pressure vessel.

SR 3.1.7.8 Verify all piping between storage tank and 24 months

,l' pump suction is unblocked.

,fDeleted: 18 (continued)

BFN-UNIT 1 3.1-25 Amendment No. 234

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY Deleted: 18 I.

SR 3.1.7.9 Verify sodium pentaborate enrichment is within the limits established by SR 3.1.7.5 by calculating within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and verifying by analysis within 30 days.

A24 mon tst AND After addition to SLC tank SR 3.1.7.10 Verify each SLC subsystem manual, power 31 days operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position, or can be aligned to the correct position.

BFN-UNIT 1 3.1-26 Amendment No. 234

SDV Vent and Drain Valves 3.1.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.8.1

--- NOTE Not required to be met on vent and drain valves closed during performance of SR 3.1.8.2.

Verify each SDV vent and drain valve is open.

31 days SR 3.1.8.2 Cycle each SDV vent and drain valve to the 92 days fully closed and fully open position.

,f 7Deleted: 181 SR 3.1.8.3 Verify each SDV vent and drain valve:

a. Closes in < 60 seconds after receipt of an actual or simulated scram signal; and

b. Opens when the actual or simulated scram signal is reset.

,24 months J.

BFN-UNIT I 3.1-29 Amendment No. 234

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.1.1.0 Perform CHANNEL CALIBRATION.

184 days SR 3.3.1.1.1.1 (Deleted)

SR 3.3.1.1.12 Perform CHANNEL FUNCTIONAL TEST.

,24 months l-Deetd:1 SR 3.3.1.1.13

---a NOTE--

Neutron detectors are excluded.

Perform CHANNEL CALIBRATION.

24 months SR 3.3.1.1.14 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.

,,Ieted:

I

_ 4Deleted : 18 SR 3.3.1.1.15 Verify Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions are not bypassed when THERMAL POWER is 2 30% RTP.

,24 months SR 3.3.1.1.16 NTE----

For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE 2.

Perform CHANNEL FUNCTIONAL TEST.

184 days BFN-UNIT I 3.3-5 Amendment No. 234

Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS NOTES------

1. Refer to Table 3.3.2.1-1 to determine which SRs apply for each Control Rod Block Function.

2. 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.

SURVEILLANCE FREQUENCY SR 3.3.2.1.1 Perform CHANNEL FUNCTIONAL TEST.

184 days SR 3.3.2.1.2

---

NOTE S

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

• 10% RTP in MODE 2.

Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.2.1.3 NOE-----

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 THERMAL POWER is

• 10% RTP in MODE 1.

Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.2.1.4

---

-- NOTE Neutron detectors are excluded.

Perform CHANNEL CALIBRATION.

,24 months

[

ed (continued)

BFN-UNIT I 3.3-18 Amendment No. 234

Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS (continued)

I.

SURVEILLANCE FREQUENCY

,fDleed: 18~

4.

SR 3.3.2.1.5 Verify the RWM is not bypassed when THERMAL POWER is

• 10% RTP.

,24 months -

- -F 4.

SR 3.3.2.1.6

___NOTE 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 reactor mode switch is in the shutdown position.

,24 months -

eetd1 Perform CHANNEL FUNCTIONAL TEST.

SR 3.3.2.1.7 Verify control rod sequences input to the Prior to declaring RWM are in conformance with BPWS.

RWM OPERABLE following loading of sequence into RWM SR 3.3.2.1.8 NOTE-Neutron detectors are excluded.

Verify the RBM:

a. Low Power Range - Upscale Function is not bypassed when THERMAL POWER is 2 27% and

• 62% RTP.

b. Intermediate Power Range - Upscale Function is not bypassed when THERMAL POWER is > 62% and

• 82% RTP.

c. High Power Range - Upscale Function is not bypassed when THERMAL POWER is

> 82% RTP.

F Deleted: 18 l

,4months BFN-UNIT 1 3.3-1 9 Amendment No. 234

Feedwater and Main Turbine High Water Level Trip Instrumentation 3.3.2.2 SURVEILLANCE REQUIREMENTS

- M fT F------

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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided feedwater and main turbine high water level trip capability is maintained.

SURVEILLANCE FREQUENCY SR 3.3.2.2.1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.2.2.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.2.2.3 Perform CHANNEL CALIBRATION. The Allowable Value shall be < 586 inches above vessel zero.

,24 months Deleted: 18 SR 3.3.2.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST including valve actuation.

,24 months -

BFN-UNIT 1 3.3-22 Amendment No. 234

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK for each required 31 days PAM instrumentation channel.

SR 3.3.3.1.2 Perform CHANNEL CALIBRATION of the 92 days Drywell and Torus H2 analyzer Functions.

SR 3.3.3.1.3 Perform CHANNEL CALIBRATION of the 184 days Reactor Pressure Functions.

F,{

Deleted: 18l SR 3.3.3.1.4 Perform CHANNEL CALIBRATION for each t24 months required PAM instrumentation channel except for the Reactor Pressure, and the Drywell and Torus H2 analyzer Functions.

BFN-UNIT I 3.3-25 Amendment No. 234

Backup Control System 3.3.3.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 24 months

,l SR 3.3.3.2.1 Verify each required control circuit and transfer switch is capable of performing the intended function.

I I

Deleted: 18

,{ Deleted: 18l

/4 Deleted: 18l SR 3.3.3.2.2 Perform CHANNEL CALIBRATION for the Suppression Pool Water Level Function.

,24 months

,li,

,24 months l'

2-4mq~

SR 3.3.3.2.3 Perform CHANNEL CALIBRATION for each required instrumentation channel except for the Suppression Pool Water Level Function.

BFN-UNIT 1 3.3-28 Amendment No. 234

EOC-RPT Instrumentation 3.3.4.1 SURVEILLANCE REQUIREMENTS

-NOTE.

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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains EOC-RPT trip capability.

SURVEILLANCE FREQUENCY SR 3.3.4.1.1 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.4.1.2 Verify TSV - Closure and TCV Fast Closure, Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is 2 30% RTP.

Perform CHANNEL CALIBRATION. The SR 3.3.4.1.3 Perform CHANNEL CALIBRATION. The Allowable Values shall be:

TSV - Closure: < 10% closed; and TCV Fast Closure, Trip Oil Pressure - Low:

2 550 psig.

~24 months,l I

,24 months 2..4 moh

[

,2-4.M q --------- II Deleted: 18

,{Deleted: 18 l

,{Deleted: 18l SR 3.3.4.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST including breaker actuation.

BFN-UNIT I 3.3-31 Amendment No. 234

ATWS-RPT Instrumentation 3.3.4.2 SURVEILLANCE REQUIREMENTS aIu%-aJI 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 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.

SURVEILLANCE FREQUENCY SR 3.3.4.2.1 Perform CHANNEL CHECK of the Reactor 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Vessel Water Level - Low Low, Level 2 Function.

SR 3.3.4.2.2 Perform CHANNEL FUNCTIONAL TEST.

92 days j,Deled: 18 SR 3.3.4.2.3 Perform CHANNEL CALIBRATION. The Allowable Values shall be:

a. Reactor Vessel Water Level - Low Low, Level 2: 2 471.52 inches above vessel zero; and

b. Reactor Steam Dome Pressure - High:

• 1 146.5 psig.

4.

SR 3.3.4.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST including breaker actuation.

I.

BFN-UNIT 1 3.3-34 Amendment No. 234

ECCS Instrumentation 3.3.5.1 SURVEILLANCE REQUIREMENTS NOTES---------_

1. Refer to Table 3.3.5.1-1 to determine which SRs apply for each ECCS Function.

2.

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 as follows: (a) for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for Functions 3.c and 3.f; and (b) for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for Functions other than 3.c and 3.f provided the associated Function or the redundant Function maintains ECCS initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.5.1.1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.5.1.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.5.1.3 Perform CHANNEL CALIBRATION.

92 days SR 3.3.5.1.4 Perform CHANNEL CALIBRATION.

184 days SR 3.3.5.1.5 Perform CHANNEL CALIBRATION.

,24 months D

,4 Deleted: 18l SR 3.3.5.1.6 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.

BFN-UNIT 1 3.3-41 Amendment No. 234

RCIC System Instrumentation 3.3.5.2 SURVEILLANCE REQUIREMENTS

,______NO BTl=-g

1. Refer to Table 3.3.5.2-1 to determine which SRs apply for each RCIC Function.

2. - 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 as follows: (a) for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for Function 2 and (b) for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for Function I provided the associated Function maintains RCIC initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.5.2.1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.5.2.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.5.2.3 Perform CHANNEL CALIBRATION.

,24 months SR 3.3.5.2.4 Perform LOGIC SYSTEM FUNCTIONAL

,24 months TEST.

/

eltd:1 Deee:1 BFN-UNIT 1 3.3-50 Amendment No. 234

Primary Containment Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS NOTES--------a-----

1. Refer to Table 3.3.6.1-1 to determine which SRs apply for each Primary Containment Isolation Function.

2.

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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains isolation capability.

SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.6.1.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.6.1.3 Perform CHANNEL CALIBRATION.

92 days SR 3.3.6.1.4 Perform CHANNEL CALIBRATION.

122 days

{Deleted: 18 SR 3.3.6.1.5 Perform CHANNEL CALIBRATION.

24 months

__Deleted: 18 SR 3.3.6.1.6 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.

ADeleted SR 3.3.6

,'CHANNEL months BFN-UNIT 1 3.3-57 Amendment No. 234

Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 2 d 3)

Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED FUNCTION OTHER CHANNELS FROM SURVEILLANCE ALLOWABLE SPECIFIED PER TRIP REQUIRED REQUIREMENTS VALUE CONDITIONS SYSTEM ACTION C,1

3. HPCI System Isolation (continued)

d. HPCI Steam Line Space HPCI Pump Room Area Temperature - High

e. HPCI Steam Line Space Torus Area (Exit)

Temperature - High

l. HPCI Steam Line Space Torus Area (Midway)

Temperature - High

g. HPCI Steam Line Space Torus Area (Entry)

Temperature - High

4. Reactor Core Isolation Cooling (RCIC) System Isolation

a. RCIC Steam Line Flow -

High

b. RCIC Steam Supply Line Pressure - Low

c. RCIC Turbine Exhaust Diaphragm Pressure - High

d. RCIC Steam Line Space RCIC Pump Room Area Temperature - High

e. RCIC Steam Line Space Torus Area (Exit)

Temperature - High

f. RCIC Steam Line Space Torus Area (Midway)

Temperature - High

g. RCIC Steam Line Space Torus Area (Entry)

Temperature - High 1,2,3 1,2,3 1,2,3 1,2.3 1,2.3 1.2.3 1.2,3 F

SR 33.6.1.2 S185F SR 33.6.1.5,

_Deleted:

6 SR 33.6.1.6.

Deleted: 7 F

SR 33.6.1.2 S167-F SR 33.6.1.6,_ _

Deleted: 6 SR 33.6.1.6..

Deleted: 7 F

SR 33.6.1.2 S167F SR 33.6.1.5...........

Deleted: 6 SR 33.6.1.6.........

Deleted: 7 F

SR 33.6.1.2 S 167-F SR 33.6.1.4_____-_------

-1Deleted:6 SR 33.6.1.6 L

D F

SR 3.3.6.1.2 S450H 20 SR 33.6.1.5 SR 3.3.6.1.6 F

SR 3.3.6.12 250psig SR 3.3.6.1.5 SR 33.6.1.6 F

SR 33.6.12 S20 psig SR 33.6.1.5 SR 33.6.1.6 F

SR 33.6.12 S 167-F SR 33fi.1.6,............

Deleted: 6............

SR 33.6.1.6,

-I--

SR 36

_Deleted: 7 F

SR 33.6.12 S167-F SR 33.6.1.6, Deleted: 6 SR 33.6.1.6_

Deleted: 7 F

SR 33.6.1.2 S167-F SR 33.6.1.6-Deee---------

Deleted: 6 SR 3.3.6.1.6,.

Deleted: 7 F

SR 33.6.12 S 167-F SR 3.3.6.1.4__---

Deleted: 6 SR 3.3.6.1.6, Deleted: 7 (continued) 1,2,3 1,2,3 1.2,3 1,2.3 2

2 2

BFN-UNIT 1 3.3-59 Amendment No. 234

Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1 -1 (page 3 d13)

Primary Containment Isolation Instrumentation APPUCABLE CONDITIONS MODES OR REQUIRED

'REFERENCED FUNCTION OTHER CHANNELS FROM SURVEILLANCE ALLOWABLE SPECIFIED PER TRIP REQUIRED REQUIREMENTS VALUE CONDITIONS SYSTEM ACTION C,1

5. ReactorWaterCleanup (RWCU) System Isolation

a. Main Steam Valve Vauft Area Temperature - High

b. Pipe Trench Area Temperature - High

c. Pump Room A Area Temperature - High

d. Pump Room B Area Temperature - High

e. Heat Exchanger Room Area (West Wal)

Temperature - High

f. Heat Exchanger Room Area (East Wall)

Temperature - High

g. SLC System Initiation

h. Reactor Vessel Water Level - Low, Level 3

6. Shutdovn Cooling System Isolation

a. Reactor Steam Dome Pressure - High

b. Reactor Vessel Water Level - Low, Level 3

c. Drywell Pressure - High 1.2.3 1.2,3 12.3 12.3 1.2.3 1.2.3 1,2 1,2,3 12,3 3,4,5 1.2.3 2

2 2

2 2

2 1(a) 2 1

2(b) 2 F

SR 33.6.12 S190F SR 33.6.1, I

Deleted:6 SR 3.3.6.1.6t 1

{Deleted:

F SR 33.6.12 S135-F SR 33.6.1.--

Deleted-6 SR 33.6.1.6.

eed:

F SR 33.6.1.2 S152-F SR 3.3.6.1.6..

Deleted: 6 SR 33.6.1.6,

____...----l Deleted: 7 F

SR 33.6.1.2 152F SR 3.3.6.1.5 Deleted: 6 SR 3.3.6.1.6,

F SR 33.6.1.2 S 1435F SR 3.3.6.1.6.

Deleted: 6-SR 3..6.1.6,

-L Deleted: 7 F

SR 33.6.1.2 1704F SR 3.3.6.1.5, Deleted: 6 SR 33.6.1.6, _ _

Deleted: 7 H

SR 33.6.1.6 NA F

SR 33.6.1.1 2 538 Inches SR 33.6.12 above vessel SR 33.6.1.5 zero SR 33.6.1.6 F

SR 33.6.12 SR 33.6.1.5 SR 33.6.1.6 I

SR 33.6.1.1 SR 33.6.12 SR 33.6.1.5 SR 33.6.1.6 F

SR 33.6.12 SR 33.6.1.5 SR 33.6.1.6 S 115 psig 2 538 inches above vessel zero S 2.5 psig (a) One SLC System Initiation signal provides logic input to close both RWCU valves.

(b) Only one channel per trip system required in MODES 4 and 5 when RHR Shutdown Cooling System integrity maintained.

BFN-UNIT 1 3.3-60 Amendment No. 234

Secondary Containment Isolation Instrumentation 3.3.6.2 SURVEILLANCE REQUIREMENTS

-NOTES

1. Refer to Table 3.3.6.2-1 to determine which SRs apply for each Secondary Containment Isolation Function.

2.

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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains secondary containment isolation capability.

3. For Functions 3 and 4, when a channel is placed in an inoperable status solely for performance of a CHANNEL CALIBRATION or maintenance, entry into associated Conditions and Required Actions may be delayed for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> provided the downscale trip of the inoperable channel is placed in the tripped condition.

SURVEILLANCE FREQUENCY SR 3.3.6.2.1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.6.2.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.6.2.3 Perform CHANNEL CALIBRATION.

,24 months

,/

Deleted: 18l SR 3.3.6.2.4 Perform LOGIC SYSTEM FUNCTIONAL

,24 months TEST.

BFN-UNIT 1 3.3-63 Amendment No. 234

CREV System Instrumentation 3.3.7.1 SURVEILLANCE REQUIREMENTS k I rT e

l'u'-j I t;5

1. Refer to Table 3.3.7.1-1 to determine which SRs apply for each CREV Function.

2.

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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains CREV initiation capability.

3.

For Functions 3 and 4, when a channel is placed in an inoperable status solely for the performance of a CHANNEL CALIBRATION or maintenance, entry into the associated Conditions and Required Actions may be delayed for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> provided the downscale trip of the inoperable channel is placed in the trip condition.

SURVEILLANCE FREQUENCY SR 3.3.7.1.1 PerformCHANNELCHECK.

24hours SR 3.3.7.1.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.7.1.3 Perform CHANNEL CALIBRATION.

92 days SR 3.3.7.1.4 Perform LOGIC SYSTEM FUNCTIONAL 184 days TEST.

Deleted: 18]

SR 3.3.7.1.5 Perform CHANNEL CALIBRATION.

24 months SR 3.3.7.1.6 Perform LOGIC SYSTEM FUNCTIONAL

,24 months D

1 TEST.

BFN-UNIT 1 3.3-68 Amendment No. 234

RPS Electric Power Monitoring 3.3.8.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.8.2.1 Perform CHANNEL FUNCTIONAL TEST.

184 days SR 3.3.8.2.2 Perform CHANNEL CALIBRATION. The 184 days Allowable Values shall be:

a. Overvoltage < 132 V, with time delay set to < 4 seconds.

b. Undervoltage 2 108.5 V, with time delay set to < 4 seconds.

c. Underfrequency 2 56 Hz, with time delay set to < 4 seconds.

__Deeed_1_

SR 3.3.8.2.3 Perform a system functional test.

24 months Dld BFN-UNIT 1 3.3-77 Amendment No. 234

S/RVs 3.4.3 SURVEILLANCE REQUIREMENTS-SURVEILLANCE FREQUENCY SR 3.4.3.1 Verify the safety function lift settings of the required 12 S/RVs are within +/- 3% of the setpoint as follows:

In accordance with the Inservice Testing Program Number of S/RVs 4

4 5

Setpoint fusigi 1105 1115 1125 Following testing, lift settings shall be within

+/- 1%.

4.

SR 3.4.3.2 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.

Verify each required S/RV opens when manually actuated.

,24 months

'l j{ eletd-18l BFN-UNIT 1 3.4-8 Amendment No. 234

RCS Leakage Detection Instrumentation 3.4.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.5.1 Perform a CHANNEL CHECK of required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> primary containment atmospheric monitoring system instrumentation.

SR 3.4.5.2 Perform a CHANNEL FUNCTIONAL TEST of 31 days required primary containment atmospheric monitoring system instrumentation.

SR 3.4.5.3 Perform a CHANNEL CALIBRATION of 184 days required drywell sump flow integrator instrumentation.

SR 3.4.5.4 Perform a CHANNEL CALIBRATION of 24 months required leakage detection system instrumentation.

Deleted: 18 I

-1 BFN-UNIT 1 3.4-14 Amendment No. 234

ECCS - Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.1.7

---NOTE 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.

Verify, with reactor pressure < 1010 and 2 920 psig, the HPCI pump can develop a flow rate 2 5000 gpm against a system head corresponding to reactor pressure.

92 days SR 3.5.1.8 a- ----

NOTE---------

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.

Verify, with reactor pressure < 165 psig, the HPCI pump can develop a flow rate 2 5000 gpm against a system head corresponding to reactor pressure.

,24 months -

,24 months l'

Deleted: 18 Deetd:1 SR 3.5.1.9 Vess linectin/s O TE--- -e cu Vessel injection/spray may be excluded.

Verify each ECCS injection/spray subsystem actuates on an actual or simulated automatic initiation signal.

(continued)

BFN-UNIT 1 3.5-6 Amendment No. 234

ECCS - Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.1.10 NOTE--

Valve actuation may be excluded.

Verify the ADS actuates on an actual or simulated automatic initiation signal.

,24 months I

SR 3.5.1.11 A--------a---NOTE -----------

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.

,tDeleted: 18 '

Deleted: 18 l

Verify each ADS valve opens when manually actuated.

,24 months

,l

,24 monthsal I.

SR 3.5.1.12 Verify automatic transfer of the power supply from the normal source to the alternate source for each LPCI subsystem inboard injection valve and each recirculation pump discharge valve.

BFN-UNIT 1 3.5-7 Amendment No. 234

ECCS - Shutdown 3.5.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY 1

SR 3.5.2.4 Verify each required ECCS pump develops the specified flow rate against a system head corresponding to the specified pressure.

In accordance with the Inservice Testing Program SYSTEM HEAD CORRESPONDING TO A VESSEL TO TORUS NO. OF DIFFERENTIAL SYSTEM FLOWRATE PUMPS PRESSURE OF Cs 2 6250 gpm 2

2105psid INDICATED NO. OF SYSTEM SYSTEM FLOW RATE PUMPS PRESSURE LPCI 2 9,000 gpm 1

2 125 psig

.1.

SR 3.5.2.5 NOTE Vessel injection/spray may be excluded.

~24 months F,

Dlte:1 Verify each required ECCS injection/spray subsystem actuates on an actual or simulated automatic initiation signal.

BFN-UNIT 1 3.5-1 1 Amendment No. 234

RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.3.1 Verify the RCIC System piping is filled with 31 days water from the pump discharge valve to the injection valve.

SR 3.5.3.2 Verify each RCIC System manual, power 31 days operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the-correct position.

SR 3.5.3.3 NOTE-------------

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.

Verify, with reactor pressure < 1010 psig and 92 days 2 920 psig, the RCIC pump can develop a flow rate 2 600 gpm against a system head corresponding to reactor pressure.

SR 3.5.3.4 NOTE---

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.

mots

,I Deleted: 18 Verify, with reactor pressure < 165 psig, the RCIC pump can develop a flow rate 2 600 gpm against a system head corresponding to reactor pressure.

(continued)

BFN-UNIT 1 3.5-1 3 Amendment No. 234

RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.3.5 e in mNOTE---e Vessel injection may be excluded.

24 monhs [ Deleted: 18

,24 months d

Verify the RCIC System actuates on an actual or simulated automatic initiation signal.

BFN-UNIT I 3.5-14 Amendment No. 234

Primary Containment 3.6.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.1.1 Perform required visual examinations and In accordance leakage rate testing except for primary with the Primary containment air lock testing, in accordance Containment with the Primary Containment Leakage Rate Leakage Rate Testing Program.

Testing Program SR 3.6.1.1.2 Verify drywell to suppression chamber differential pressure does not decrease at a rate > 0.25 inch water gauge per minute over a 10 minute period at an initial differential pressure of 1 psid.

,24 months I{ Deleted:18 BFN-LINIT 1 3.6-2 Amendment No. 234

PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.1.3.5 Verify the isolation time of each power In accordance operated, automatic PCIV, except for MSIVs, with the Inservice is within limits.

Testing Program SR 3.6.1.3.6 Verify the isolation time of each MSIV is 2 3 In accordance seconds and < 5 seconds.

with the Inservice Testing Program I

SR 3.6.1.3.7 Verify each automatic PCIV actuates to the isolation position on an actual or simulated isolation signal.

,24 months

,F'

,24 months

'l'

,4Deleted: 18l Deeed: 18 4

SR 3.6.1.3.8 Verify each reactor instrumentation line EFCV actuates to the isolation position on a simulated instrument line break signal.

4 SR 3.6.1.3.9 Remove and test the explosive squib from each shear isolation valve of the TIP System.

I tDeleted: 18 l

.24 months on a is' STAGGERED TEST BASIS SR 3.6.1.3.10 Verify leakage rate through each MSIV is In accordance

< 11.5 scfh when tested at 2 25 psig.

with the Primary Containment Leakage Rate Testing Program SR 3.6.1.3.11 Verify combined leakage through water tested In accordance lines that penetrate primary containment are with the Primary within the limits specified in the Primary Containment Containment Leakage Rate Testing Program.

Leakage Rate Testing Program BFN-UNIT 1 3.6-16 Amendment No. 234

Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.5.1 NOTES

1. Not required to be met for vacuum breakers that are open during Surveillances.

2. Not required to be met for vacuum breakers open when performing their intended function.

Verify each vacuum breaker is closed.

14 days SR 3.6.1.5.2 Perform a functional test of each vacuum 92 days breaker.

, lDeleted: 18 SR 3.6.1.5.3 Verify the opening setpoint of each vacuum breaker is < 0.5 psid.

,24 months I,F/_

i BFN-UNIT I 3.6-21 Amendment No. 234

Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.6.1

-- NOTES----

1. Not required to be met for vacuum breakers that are open during Surveillances.

2. One drywell suppression chamber vacuum breaker may be nonfully closed so long as it is determined to be not more than 30 open as indicated by the position lights.

Verify each vacuum breaker is closed.

14 days SR 3.6.1.6.2 Perform a functional test of each required In accordance vacuum breaker.

wth the Inservice Testing Program SR 3.6.1.6.3 Verify the differential pressure required to open each vacuum breaker is < 0.5 psid.

,24 months

,{

eeed: 18l BFN-UNIT 1 3.6-23 Amendment No. 234

Main Turbine Bypass System 3.7.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1 Verify one complete cycle of each main 31 days turbine bypass valve.

SR 3.7.5.2 Perform a system functional test.

24 months SR 3.7.5.3 Verify the TURBINE BYPASS SYSTEM

,24 months RESPONSE TIME is within limits.

_," Deleted: 18l

,{ Deleted: 18l

.1 BFN-UNIT I 3.7-17 Amendment No. 234

ENCLOSURE 3 TECHNICAL SPECIFICATION CHANGE (TS-433) -

24 MONTH FUEL CYCLE PROPOSED TECHNICAL SPECIFICATION CHANGES (CLEAN PAGES)

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY I.

SR 3.1.7.5 Verify the SLC conditions satisfy the following equation:

( C

)(

Q )(

E

)

(13 wt. %)(86 gpm)(19.8 atom%)

where, C = sodium pentaborate solution concentration (weight percent)

Q = pump flow rate (gpm) 31 days AND Once within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after water or boron is added to the solution E = Boron-10 enrichment (atom percent Boron-1 0)

SR 3.1.7.6 Verify each pump develops a flow rate 2 39 24 months gpm at a discharge pressure 2 1275 psig.

SR 3.1.7.7 Verify flow through one SLC subsystem from 24 months on a pump into reactor pressure vessel.

STAGGERED TEST BASIS SR 3.1.7.8 Verify all piping between storage tank and 24 months pump suction is unblocked.

(continued)

BFN-UNIT 1 3.1-25 Amendment No. 234

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.1.7.9 Verify sodium pentaborate enrichment is within 24 months the limits established by SR 3.1.7.5 by calculating within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and verifying by AND analysis within 30 days.

After addition to SLC tank SR 3.1.7.10 Verify each SLC subsystem manual, power 31 days operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position, or can be aligned to the correct position.

BFN-UNIT 1 3.1-26 Amendment No. 234

SDV Vent and Drain Valves 3.1.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.8.1 NOTE------

Not required to be met on vent and drain valves closed during performance of SR 3.1.8.2.

Verify each SDV vent and drain valve is open.

31 days SR 3.1.8.2 Cycle each SDV vent and drain valve to the 92 days fully closed and fully open position.

SR 3.1.8.3 Verify each SDV vent and drain valve:

24 months

a. Closes in < 60 seconds after receipt of an actual or simulated scram signal; and

b. Opens when the actual or simulated scram signal is reset.

BFN-UNIT 1 3.1-29 Amendment No. 234

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.1.1.10 Perform CHANNEL CALIBRATION.

184 days S R 3.3. 1. 1.11I (Deleted)

SR 3.3.1.1.12 Perform CHANNEL FUNCTIONAL TEST.

24 months SR 3.3.1.1.13 NOT E---

Neutron detectors are excluded.

Perform CHANNEL CALIBRATION.

24 months SR 3.3.1.1.14 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.

SR 3.3.1.1.15 Verify Turbine Stop Valve-Closure and 24 months Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions are not bypassed when THERMAL POWER is 2 30% RTP.

SR 3.3.1.1.16 NOTE For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after entering MODE 2.

Perform CHANNEL FUNCTIONAL TEST.

184 days BFN-UNIT 1 3.3-5 Amendment No. 234

Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS a

NOTES

1. Refer to Table 3.3.2.1-1 to determine which SRs apply for each Control Rod Block Function.

2.

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.

SURVEILLANCE FREQUENCY SR 3.3.2.1.1 Perform CHANNEL FUNCTIONAL TEST.

184 days SR 3.3.2.1.2 NOTE 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 < 10% RTP in MODE 2.

Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.2.1.3 NOTE-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 THERMAL POWER is < 10% RTP in MODE1.

Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.2.1.4 NOTE-Neutron detectors are excluded.

Perform CHANNEL CALIBRATION.

24 months (continued)

BFN-UNIT 1 3.3-1 8 Amendment No. 234

Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.3.2.1.5 Verify the RWM is not bypassed when 24 months THERMAL POWER is

• 10% RTP.

SR 3.3.2.1.6 NOTE----G 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 reactor mode switch is in the shutdown position.

Perform CHANNEL FUNCTIONAL TEST.

24 months SR 3.3.2.1.7 Verify control rod sequences input to the Prior to declaring RWM are in conformance with BPWS.

RWM OPERABLE following loading of sequence into RWM SR 3.3.2.1.8 NOTE--

Neutron detectors are excluded.

Verify the RBM:

a. Low Power Range -- Upscale Function is 24 months not bypassed when THERMAL POWER is

Ž 27% and < 62% RTP.

b. Intermediate Power Range -- Upscale Function is not bypassed when THERMAL POWER is > 62% and < 82% RTP.

c. High Power Range - Upscale Function is not bypassed when THERMAL POWER is

> 82% RTP.

BFN-UNIT I 3.3-1 9 Amendment No. 234

Feedwater and Main Turbine High Water Level Trip Instrumentation 3.3.2.2 SURVEILLANCE REQUIREMENTS

-NOTE 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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided feedwater and main turbine high water level trip capability is maintained.

SURVEILLANCE FREQUENCY SR 3.3.2.2.1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.2.2.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.2.2.3 Perform CHANNEL CALIBRATION. The 24 months Allowable Value shall be < 586 inches above vessel zero.

SR 3.3.2.2.4 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST including valve actuation.

BFN-UNIT 1 3.3-22 Amendment No. 234

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK for each required 31 days PAM instrumentation channel.

SR 3.3.3.1.2 Perform CHANNEL CALIBRATION of the 92 days Drywell and Torus H2 analyzer Functions.

SR 3.3.3.1.3 Perform CHANNEL CALIBRATION of the 184 days Reactor Pressure Functions.

SR 3.3.3.1.4 Perform CHANNEL CALIBRATION for each 24 months required PAM instrumentation channel except for the Reactor Pressure, and the Drywell and Torus H2 analyzer Functions.

BFN-UNIT 1 3.3-25 Amendment No. 234

Backup Control System 3.3.3.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.3.2.1 Verify each required control circuit and 24 months transfer switch is capable of performing the intended function.

SR 3.3.3.2.2 Perform CHANNEL CALIBRATION for the 24 months Suppression Pool Water Level Function.

SR 3.3.3.2.3 Perform CHANNEL CALIBRATION for each 24 months required instrumentation channel except for the Suppression Pool Water Level Function.

BFN-UNIT I 3.3-28 Amendment No. 234

EOC-RPT Instrumentation 3.3.4.1 SURVEILLANCE REQUIREMENTS

---

NOTE 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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains EOC-RPT trip capability.

SURVEILLANCE FREQUENCY SR 3.3.4.1.1 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.4.1.2 Verify TSV - Closure and TCV Fast Closure, 24 months Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is 2 30% RTP.

SR 3.3.4.1.3 Perform CHANNEL CALIBRATION. The 24 months Allowable Values shall be:

TSV - Closure:

• 10% closed; and TCV Fast Closure, Trip Oil Pressure - Low.

2 550 psig.

SR 3.3.4.1.4 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST including breaker actuation.

BFN-UNIT 1 3.3-31 Amendment No. 234

ATWS-RPT Instrumentation 3.3.4.2 SURVEILLANCE REQUIREMENTS f-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 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.

SURVEILLANCE FREQUENCY SR 3.3.4.2.1 Perform CHANNEL CHECK of the Reactor 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Vessel Water Level - Low Low, Level 2 Function.

SR 3.3.4.2.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.4.2.3 Perform CHANNEL CALIBRATION. The 24 months Allowable Values shall be:

a. Reactor Vessel Water Level - Low Low, Level 2: Ž471.52 inches above vessel zero; and

b. Reactor Steam Dome Pressure - High:

< 1146.5 psig.

SR 3.3.4.2.4 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST including breaker actuation.

BFN-UNIT I 3.3-34 Amendment No. 234

ECCS Instrumentation 3.3.5.1 SURVEILLANCE REQUIREMENTS L I Pr e

A--i-----------N a _- "

1. Refer to Table 3.3.5.1-1 to determine which SRs apply for each ECCS Function.

2.

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 as follows: (a) for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for Functions 3.c and 3.f; and (b) for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for Functions other than 3.c and 3.f provided the associated Function or the redundant Function maintains ECCS initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.5.1.1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.5.1.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.5.1.3 Perform CHANNEL CALIBRATION.

92 days SR 3.3.5.1.4 Perform CHANNEL CALIBRATION.

184 days SR 3.3.5.1.5 Perform CHANNEL CALIBRATION.

24 months SR 3.3.5.1.6 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.

BFN-UNIT I 3.3-41 Amendment No. 234

RCIC System Instrumentation 3.3.5.2 SURVEILLANCE REQUIREMENTS

--- NOTES------

a

1. Refer to Table 3.3.5.2-1 to determine which SRs apply for each RCIC Function.

2.

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 as follows: (a) for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for Function 2 and (b) for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for Function 1 provided the associated Function maintains RCIC initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.5.2.1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.5.2.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.5.2.3 Perform CHANNEL CALIBRATION.

24 months SR 3.3.5.2.4 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.

BFN-UNIT 1 3.3-50 Amendment No. 234

Primary Containment Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS

---

NOTES------------

1. Refer to Table 3.3.6.1-1 to determine which SRs apply for each Primary Containment Isolation Function.

2. 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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains isolation capability.

SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.6.1.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.6.1.3 Perform CHANNEL CALIBRATION.

92 days SR 3.3.6.1.4 Perform CHANNEL CALIBRATION.

122 days SR 3.3.6.1.5 Perform CHANNEL CALIBRATION.

24 months SR 3.3.6.1.6 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.

I BFN-UNIT I 3.3-57 Amendment No. 234

Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1.1 (page 2 o 3)

Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED FUNCTION OTHER CHANNELS FROM SURVEILLANCE ALLOWABLE SPECIFIED PER TRIP REQUIRED REQUIREMENTS VALUE CONDITIONS SYSTEM ACTION C.1

3. HPCI System Isolation (continued)

d. HPCI Steam Line Space HPCI Pump Room Area Temperature - High

e. HPCI Steam Line Space Torus Area (Exit)

Temperature - High

f. HPCI Steam Line Space Torus Area (idway)

Temperature - High

g. HPCI Steam Line Space Torus Area (Entry)

Temperature - High

4. Reactor Core Isolation Cooling (RCIC) System Isolation

a. RCIC Steam Line Flow -

High

b. RCIC Steam Supply Line Pressure - Low

c. RCIC Turbine Exhaust Diaphragm Pressure - High

d. RCIC Steam Line Space RCIC Pump Room Area Temperature - High

e. RCIC Steam Line Space Torus Area (ExiH)

Temperature - High

f. RCIC Steam Line Space Torus Area (Midway)

Temperature - High

g. RCIC Steam Line Space Torus Area (Entry)

Temperature - High 1.2.3 2

1.2.3 1,2,3 2

1,2,3 1.2,3 1,2,3 1,2.3 1,2,3 1.2,3 1.2,3 1,2,3 F

SR 33.6.1.2 SR 33.6.1.5 SR 33.6.1.6 F

SR 33.6.12 SR 33.6.1.5 SR 33.6.1.6 F

SR 33.6.12 SR 33.6.1.5 SR 33.6.1.6 F

SR 33.6.12 SR 33.6.1.5 SR 33.6.1.6 F

SR 33.6.12 SR 33.6.1.5 SR 33.6.1.6 F

SR 33.6.12 SR 3.3f6.1.5 SR 33.6.1.6 F

SR 33.6.12 SR 33.6.1.5 SR 33.6.1.6 F

SR 33.6.12 SR 3.3.6.1.5 SR 3.3.6.1.6 F

SR 3.3.6.12 SR 3.3.6.1.5 SR 3.3.6.1.6 F

SR 3.3.6.12 SR 3.3.6.1.5 SR 3.3f6.1.6 F

SR 3.3.6.12 SR 33.6.1.5 SR 33.6.1.6 S 185-F S 167-F S 167-F S 167-F I

I I

I -

S 450' H20 2Ž50 psig S 20 psig S 167-F S 167-F S 167-F S 167F I

I I

I (continued)

BFN-UNIT 1 3.3-59 Amendment No. 234

Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 3 d13)

Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED FUNCTION OTHER CHANNELS FROM SURVEILLANCE ALLOWABLE SPECIFIED PER TRIP REQUIRED REQUIREMENTS VALUE CONDITIONS SYSTEM ACTION C.1

5. Reactor Waler Cleanup (RWCU) System Isolation

a. Main Steam Valve Vault Area Temperature - High

b. Pipe Trench Area Temperature - High

c. Pump Room A Area Temperature - High

d. Pump Room B Area Temperature - High

e. Heat Exchanger Room Area (West Wall)

Temperature - High

f. Heat Exchanger Room Area (East Wall)

Temperature - High

g. SLC System Initiation

h. Reactor Vessel Water Level - Low, Level 3

6. Shutdown Cooling System Isolation

a. Reactor Steam Dome Pressure - High

b. ReactorVesselWater Level - Low, Level 3

c. Drywell Pressure - High 1,2,3 1.2,3 1.2.3 1,2.3 1,2,3 1.2,3 1,2 1.2,3 1,2,3 3.4.5 2

2 2

2 2

2 1 (a) 2 I

2Qb)

F SR 33.6.1.2 SR 33.6.1.5 SR 3.3.6.1.6 F

SR 33.6.1.2 SR 33.6.1.5 SR 3.3.6.1.6 F

SR 3.3.6.1.2 SR 3.3.6.1.5 SR 3.3.6.1.6 F

SR 3.3.6.1.2 SR 33.6.1.5 SR 3.3.6.1.6 F

SR 33.6.12 SR 33.6.1.5 SR 33.6.1.6 F

SR 33.6.1.2 SR 33.6.1.5 SR 33.6.1.6 H

SR 33.6.1.6 F

SR 33.6.1.1 SR 33.6.1.2 SR 33.6.1.5 SR 33.6.1.6 F

SR 33.6.1.2 SR 33.6.1.5 SR 33.6.1.6 I

SR 33.6.1.1 SR 33.6.12 SR 33.6.1.5 SR 33.6.1.6 F

SR 33.6.1.2 SR 33.6.1.5 SR 33.6.1.6 S 190-F I

S 135-F I

S 152-F I

S 152-F I

S 143-F I

S 170-F I

NA 2 538 Inches above vessel zero S 115 psig 2 538 inches above vessel zero S 2.5 psig 1.2.3 (a) One SLC System Iniation signal provides logic input to close both RWCU valves.

(b) Only one channel per trip syslem required in MODES 4 and 5 when RHR Shutdown Cooring System integrity maintained.

BFN-UNIT 1 3.3-60 Amendment No. 234

Secondary Containment Isolation Instrumentation 3.3.6.2 SURVEILLANCE REQUIREMENTS NOTES

1. Refer to Table 3.3.6.2-1 to determine which SRs apply for each Secondary Containment Isolation Function.

2.

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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains secondary containment isolation capability.

3. For Functions 3 and 4, when a channel is placed in an inoperable status solely for performance of a CHANNEL CALIBRATION or maintenance, entry into associated Conditions and Required Actions may be delayed for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> provided the downscale trip of the inoperable channel is placed in the tripped condition.

SURVEILLANCE FREQUENCY SR 3.3.6.2.1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.6.2.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.6.2.3 Perform CHANNEL CALIBRATION.

24 months SR 3.3.6.2.4 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.

BFN-UNIT 1 3.3-63 Amendment No. 234

CREV System Instrumentation 3.3.7.1 SURVEILLANCE REQUIREMENTS sns=e 1

-'VIL---

t A

1. Refer to Table 3.3.7.1-1 to determine which SRs apply for each CREV Function.

2.

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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains CREV initiation capability.

3.

For Functions 3 and 4, when a channel is placed in an inoperable status solely for the performance of a CHANNEL CALIBRATION or maintenance, entry into the associated Conditions and Required Actions may be delayed for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> provided the downscale trip of the inoperable channel is placed in the trip condition.

SURVEILLANCE FREQUENCY SR 3.3.7.1.1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.7.1.2 Perform CHANNEL FUNCTIONAL TEST.

92 days SR 3.3.7.1.3 Perform CHANNEL CALIBRATION.

92 days SR 3.3.7.1.4 Perform LOGIC SYSTEM FUNCTIONAL 184 days TEST.

SR 3.3.7.1.5 Perform CHANNEL CALIBRATION.

24 months SR 3.3.7.1.6 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.

BFN-UNIT I 3.3-68 Amendment No. 234

RPS Electric Power Monitoring 3.3.8.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.8.2.1 Perform CHANNEL FUNCTIONAL TEST.

184 days SR 3.3.8.2.2 Perform CHANNEL CALIBRATION. The 184 days Allowable Values shall be:

a. Overvoltage

• 132 V, with time delay set to < 4 seconds.

b. Undervoltage 2 108.5 V, with time delay set to < 4 seconds.

c. Underfrequency > 56 Hz, with time delay set to < 4 seconds.

SR 3.3.8.2.3 Perform a system functional test.

24 months BFN-UNIT 1 3.3-77 Amendment No. 234

S/RVs 3.4.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.3.1 Verify the safety function lift settings of the required 12 S/RVs are within +/- 3% of the setpoint as follows:

Number of Setpoint S/RVs fpjig 4

1105 4

1115 5

1125 Following testing, lift settings shall be within

+/- 1%.

In accordance with the Inservice Testing Program SR 3.4.3.2 NOTE----------------

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.

Verify each required S/RV opens when 24 months manually actuated.

BFN-UNIT I 3.4-8 Amendment No. 234

RCS Leakage Detection Instrumentation 3.4.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.5.1 Perform a CHANNEL CHECK of required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> primary containment atmospheric monitoring system instrumentation.

SR 3.4.5.2 Perform a CHANNEL FUNCTIONAL TEST of 31 days required primary containment atmospheric monitoring system instrumentation.

SR 3.4.5.3 Perform a CHANNEL CALIBRATION of 184 days required drywell sump flow integrator instrumentation.

SR 3.4.5.4 Perform a CHANNEL CALIBRATION of 24 months required leakage detection system instrumentation.

BFN-UNIT I 3.4-14 Amendment No. 234

ECCS - Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY

+

SR 3.5.1.7 NOTE 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.

Verify, with reactor pressure < 1010 and 2 920 psig, the HPCI pump can develop a flow rate 2 5000 gpm against a system head corresponding to reactor pressure.

92 days SR 3.5.1.8 NOTE----

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.

Verify, with reactor pressure < 165 psig, the 24 months HPCI pump can develop a flow rate 2 5000 gpm against a system head corresponding to reactor pressure.

SR 3.5.1.9

---

NOTE--

Vessel injection/spray may be excluded.

Verify each ECCS injection/spray subsystem 24 months actuates on an actual or simulated automatic initiation signal.

(continued)

BFN-UNIT 1 3.5-6 Amendment No. 234

ECCS - Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.1.10 NOTE-Valve actuation may be excluded.

Verify the ADS actuates on an actual or 24 months simulated automatic initiation signal.

SR 3.5.1.11 N

O T E--------

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.

Verify each ADS valve opens when manually 24 months actuated.

SR 3.5.1.12 Verify automatic transfer of the power supply 24 months from the normal source to the alternate source for each LPCI subsystem inboard injection valve and each recirculation pump discharge valve.

BFN-UNIT 1 3.5-7 Amendment No. 234

ECCS - Shutdown 3.5.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.2.4 Verify each required ECCS pump develops the specified flow rate against a system head corresponding to the specified pressure.

SYSTEM HEAD CORRESPONDING TO A VESSEL TO TORUS NO. OF DIFFERENTIAL SYSTEM FLOWRATE PUMPS PRESSURE OF Cs 2 6250 gpm 2

2105 psid INDICATED NO. OF SYSTEM SYSTEM FLOW RATE PUMPS PRESSURE LPCI 2 9,oo0 gpm 1

2125 psig In accordance with the Inservice Testing Program SR 3.5.2.5 Ad-NOTED--___

Vessel injection/spray may be excluded.

Verify each required ECCS injection/spray 24 months subsystem actuates on an actual or simulated automatic initiation signal.

BFN-UNIT I 3.5-1 1 Amendment No. 234

RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.3.1 Verify the RCIC System piping is filled with 31 days water from the pump discharge valve to the injection valve.

SR 3.5.3.2 Verify each RCIC System manual, power 31 days operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.5.3.3 NOTE 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.

Verify, with reactor pressure < 1010 psig and 92 days 2 920 psig, the RCIC pump can develop a flow rate 2 600 gpm against a system head corresponding to reactor pressure.

SR 3.5.3.4 NOTEE-----

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.

Verify, with reactor pressure < 165 psig, the 24 months RCIC pump can develop a flow rate 2 600 gpm against a system head corresponding to reactor pressure.

(continued)

BFN-UNIT I 3.5-1 3 Amendment No. 234

RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.5.3.5

-NOTE Vessel injection may be excluded.

Verify the RCIC System actuates on an actual 24 months or simulated automatic initiation signal.

BFN-UNIT 1 3.5-14 Amendment No. 234

Primary Containment 3.6.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.1.1 Perform required visual examinations and In accordance leakage rate testing except for primary with the Primary containment air lock testing, in accordance Containment with the Primary Containment Leakage Rate Leakage Rate Testing Program.

Testing Program SR 3.6.1.1.2 Verify drywell to suppression chamber 24 months differential pressure does not decrease at a rate > 0.25 inch water gauge per minute over a 10 minute period at an initial differential pressure of 1 psid.

BFN-UNIT I 3.6-2 Amendment No. 234

PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.6.1.3.5 Verify the isolation time of each power In accordance operated, automatic PCIV, except for MSIVs, with the Inservice is within limits.

Testing Program SR 3.6.1.3.6 Verify the isolation time of each MSIV is 2 3 In accordance seconds and 5 5 seconds.

with the Inservice Testing Program SR 3.6.1.3.7 Verify each automatic PCIV actuates to the 24 months isolation position on an actual or simulated isolation signal.

SR 3.6.1.3.8 Verify each reactor instrumentation line EFCV 24 months actuates to the isolation position on a simulated instrument line break signal.

SR 3.6.1.3.9 Remove and test the explosive squib from 24 months on a each shear isolation valve of the TIP System.

STAGGERED TEST BASIS SR 3.6.1.3.10 Verify leakage rate through each MSIV is In accordance

< 11.5 scfh when tested at 2 25 psig.

with the Primary Containment Leakage Rate Testing Program SR 3.6.1.3.11 Verify combined leakage through water tested In accordance lines that penetrate primary containment are with the Primary within the limits specified in the Primary Containment Containment Leakage Rate Testing Program.

Leakage Rate Testing Program BFN-UNIT 1 3.6-16 Amendment No. 234

Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.5.1

1. Not required to be met for vacuum breakers that are open during Surveillances.

2. Not required to be met for vacuum breakers open when performing their intended function.

Verify each vacuum breaker is closed.

14 days SR 3.6.1.5.2 Perform a functional test of each vacuum 92 days breaker.

SR 3.6.1.5.3 Verify the opening setpoint of each vacuum 24 months breaker is < 0.5 psid.

BFN-UNIT I 3.6-21 Amendment No. 234

Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.6 SURVEILLANCE REQUIREMENTS q.

SURVEILLANCE FREQUENCY 4

SR 3.6.1.6.1 NOTES------

1. Not required to be met for vacuum breakers that are open during Surveillances.

2. One drywell suppression chamber vacuum breaker may be nonfully closed so long as it is determined to be not more than 30 open as indicated by the position lights.

Verify each vacuum breaker is closed.

14 days SR 3.6.1.6.2 Perform a functional test of each required In accordance vacuum breaker.

with the Inservice Testing Program SR 3.6.1.6.3 Verify the differential pressure required to 24 months open each vacuum breaker is

• 0.5 psid.

BFN-UNIT 1 3.6-23 Amendment No. 234

Main Turbine Bypass System 3.7.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1 Verify one complete cycle of each main 31 days turbine bypass valve.

_____________________________________________________________________Deleted:

Dle 18: l SR 3.7.5.2 Perform a system functional test.

,24 months

/,4 Deleted: 18 SR 3.7.5.3 Verify the TURBINE BYPASS SYSTEM 24 months RESPONSE TIME is within limits.

BFN-UNIT 1 3.7-1 7 Amendment No. 234