RBG-47191, Changes to Technical Specification 3.8.1; AC Sources - Operating

Changes to Technical Specification 3.8.1; AC Sources - Operating

ML11348A237
Person / Time
Site:	River Bend
Issue date:	12/08/2011
From:	Roberts J Entergy Operations
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
RBG-47191
Download: ML11348A237 (41)

Text

Entergy Operations, Inc.

River Bend Station Ent 5485 U.S. Highway 61 N otrgy St. Francisville, LA 70775 Tel 225-381-4374 Jerry C. Roberts Director, Nuclear Safety Assurance RBG-47191 December 8, 2011 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555

SUBJECT:

License Amendment Request Changes to Technical Specification 3.8.1;" AC Sources - Operating" River Bend Station, Unit 1 Docket No. 50-458 License No. NPF-47

Dear Sir or Madam:

In accordance with the provisions of Section 50.90 of Title 10 of the Code of Federal Regulations (10 CFR), Entergy Operations, Inc. (Entergy) is submitting a request for an amendment to the Technical Specifications (TS) 3.8.1 ;"AC Sources - Operating." This request will revise Technical Specification (TS) 3.8.1 and the associated Bases, to expand ts scope to include provisions for testing of the automatic transfer function from the station 22 kV bus to offsite power for Division I1l. This Surveillance Requirement (SR) is being added to ensure availability of offsite power after loss of the station (onsite) 22 kV bus when offsite power remains available.

In addition to the above, notes are being added to the Limiting Condition for Operation (LCO) and SR to require this feature when Division III is powered by onsite power. Also ACTION's are added to ensure this transfer from onsite to offsite is maintained when a required offsite power source is lost.

The proposed changes have been evaluated in accordance 10 CFR 50.92(c). It has been determined that the changes involve no significant hazards considerations. Attachment 1 provides the No Significant Hazards Consideration for the change. provides a description of the proposed change. Attachment 2 provides the existing TS pages marked up to show the proposed changes. Attachment 3 provides the existing TS Bases pages marked up to show the proposed change (for information only). provides a summary of the regulatory commitments made in this submittal.

This change has been reviewed and approved by the Onsite Safety Review Committee (OSRC).

RBG-47191 Page 2 of 2 Although this request is neither exigent nor emergency, your prompt review is requested.

Once approved, the amendment shall be implemented prior to startup from the next refueling outage, currently scheduled for early 2013. If you have any questions or require additional information, please contact Mr. Joseph A. Clark at (225) 381-4177.

I declare under penalty of perjury that the foregoing is true and correct. Executed on December 8, 2011 Sincerely, C1-RIJAC/bmb Attachments:

1. Analysis of Proposed Technical Specification Change

2. Proposed Technical Specification Changes (mark-up)

3. Changes to Technical Specification Bases Pages - For Information Only

4. List of Regulatory Commitments cc: Regional Administrator U. S. Nuclear Regulatory Commission Region IV 612 E. Lamar Blvd., Suite 400 Arlington, TX 76011-4125 NRC Senior Resident Inspector P. 0. Box 1050 St. Francisville, LA 70775 U. S. Nuclear Regulatory Commission Attn: Mr. Alan B. Wang MS 0-8 B1 Washington, DC 20555-0001 Department of Environmental Quality Office of Environmental Compliance Radiological Emergency Planning and Response Section JiYoung Wiley P.O. Box 4312 Baton Rouge, LA 70821-4312

Attachment I RBG-47191 Analysis of Proposed Technical Specification Change RBG-47191 Page 1 of 12

1.0 DESCRIPTION

The proposed amendment would revise River Bend Station (RBS), Unit 1 Technical Specification (TS) 3.8.1; "AC Sources - Operating," to expand the scope to include provisions for testing of the automatic transfer function from the onsite 22 kV bus to offsite power for Division III and the associated Standby Service Water Pump powered by the Division III bus. The change will also add ACTION's to ensure the Division III bus remains powered.

These proposed requirements are being added to ensure availability of offsite power after loss of the station 22 kV bus when offsite power remains available.

2.0 PROPOSED CHANGE

The design configuration addressed by this change is the transfer from an onsite power source (main generator output of 22kV) to the offsite power.

A review of this change to NUREG-1 434 concluded the Surveillance Requirement (SR) 3.8.1.8 was similar but is not directly applicable. The standard SR addresses automatic transfer from one offsite power to an alternate. While NUREG-1 434 was not directly applicable a similar configuration was found as noted in Section 6, Precedence, of this attachment. The proposed specification and associated BASES are based upon these examples.

The proposed change would add the requirement to test the automatic transfer function for station service transformer STX-XNS1C when powered from the station 22 kV bus.

The changes will add a note to the Limiting Condition for Operation (LCO) and an additional surveillance requirement.

The note is to be added to LCO 3.8.1 limiting the requirement to have the automatic transfer function operable when the Division III bus is connected directly to onsite power.

This note will state:

The automatic transfer function for the Division III 4.16 kV system buses shall be OPERABLE whenever the 22 kV onsite circuit is supplying Division III safety related bus E22-S004 through NNS-SWG1A or NNS-SWG1B 4.16 kV buses from normal station service transformer STX-XNS1C.

In addition to the note added to LCO 3.8.1, two new REQUIRED ACTIONs will be added. The first new REQUIRED ACTION (A.2) will be added to verify automatic transfer of onsite circuit supplying Division III safety related bus to the offsite circuit is aligned to the powered transformer. This REQUIRED ACTION will state:

Verify E22-S004 will transfer to the preferred station transformer powered by the OPERABLE offsite circuit.

RBG-47191 Page 2 of 12 This ACTION will be modified to only require verification if the Division III safety related bus is powered by the 22 kV onsite circuit.

The COMPLETION TIME will state:

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter.

The second REQUIRED ACTION (B) will be added to restore Division III power to the preferred station service transformers when the automatic transfer function is not OPERABLE. This REQUIRED ACTION will state:

Restore Division III power source to the preferred station service transformers The COMPLETION TIME will state:

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> The new surveillance requirement will be added as SR 3.8.1.9. This new SR will require the automatic transfer function to be tested on a 24 month frequency.

Verify automatic transfer of bus E22-S004 through NNS-SWG1A or NNS-SWG1 B from the22 kV onsite circuit to required alternate offsite circuit.

In addition to the new SR, a note will be added to the SR which will state:

Only required to be met if 22 kV onsite circuit is supplying Division III safety related bus E22-S004 through NNS-SWG1A or NNS-SWG1B 4.16 kV buses from normal power transformer STX-XNS1C.

The proposed TS are included in Attachment 2 The changes to the affected TS Bases pages will be incorporated in accordance with the TS Bases Control Program. The proposed BASES are included in Attachment 3, for information.

3.0 BACKGROUND

3.1 License Basis As a result of a review of plant configuration, the decision was made to include the option of powering the Division III bus through station service transformer STX-XNS1C.

This transformer is fed from the main generator. The proposed revision to SR 3.8.1.8, and the associated Bases, will expand the scope to include provisions for testing the automatic transfer function of the Division III bus from STX-XNS1C to offsite power.

The description of the current power system at RBS is contained in Section 8 of the USAR. Section 8.1 and 8.3 identifies the current transformer design and distribution configuration. Applicable USAR figures for this discussion are USAR Figure 8.1-6 and USAR Figure 8.3-3.

RBG-47191 Page 3 of 12 USAR Chapter 8, Section 8.1.4 states that "if the unit auxiliary loads are being supplied through the normal transformers, automated throw-over from normal to preferred source occurs (as described in Section 8.3.1.1.3) after unit trip or upon loss of normal power."

Section 8.3.1.1.3 describes the 13.8 KV and 4.16 KV systems. It specifically states that the normal AC power supply can provide electrical power for all station auxiliary loads when the main generator is operating. It consists of three normal station service transformers STX-XNS1A, STX-XNS1B and STX-XNS1C. However, electric power through these transformers is not currently used to power the safety related buses.

Section 8.3.1.1.3.3 specifically describes how the fast transfer scheme is blocked if the switchgear (NNS-SWG1A or 1B) is powering NNS-SWG1C, and high pressure core spray (HPCS) and / or standby service water (SWP) pump 2C is running. The section states that "No automatic transfer of NNS-SWG1C alone is provided, it will fast transfer with NNS-SWG1A or NNS-SWG1B from the normal service transformer to the preferred station service transformer unless blocked as described above." Thus, section 8.3.1.1.3.3 is in accordance with the RBS design basis documents.

USAR Section 8.3.1.1.5.5, "Testability of Offsite/Onsite Power Systems," currently addresses the testability of the transfer of the 13.8 KV normal power supply to the preferred power supply. This section will require revision to include testing of the 4.16 KV normal power supply automatic transfer to preferred power supply.

Technical Specification SR 3.8.1.8 does not address testing of an automatic transfer function. This is because current implementation of the AC power supplies does not depend on a transfer of power sources. This configuration is~controlled by procedure.

The initial plant licensing Final Safety Analysis Report (FSAR), sections 8.1 and 8.3 indicate the automatic transfer from STX-XNS1 C to offsite power was included in the initial design. The use of this automatic transfer feature is not included in current plant procedures. This configuration is not currently relied upon for plant operation.

A review of plant TS prior to conversion to Improved Technical Specifications confirmed the previous surveillances did not address testing of an automatic transfer function.

As discussed in the technical justification, this function will not affect the availability of the emergency diesel generators.

3.2 Technical Basis The design configuration addressed by this change is the transfer from an onsite power source (main generator output of 22kV) to the offsite power. As described below the automatic transfer will ensure power is available from an offsite source after the loss of the main generator.

The automatic transfer system consists of two subsystems. The first a "fast" transfer which switches the power source for the Division III bus from on site to an offsite source while maintaining power to the Division III bus. The second is a "slow" transfer which RBG-47191 Page 4 of 12 allows the bus power to decay sufficiently. The transfer functions are independent and operate sequentially.

Differences between the fast and slow transfer functions are:

The fast transfer will continue to power the non-safety related loads that are powered by associated non-safety buses.

If the major motor loads on the safety related bus, HPCS pump and SWP-P2C, are in operation the fast transfer is blocked.

The slow transfer will not power the non-safety related loads powered by the associated non-safety bus and the major motor loads on the safety related bus will be re-powered with the Division III bus.

As discussed in the technical justification, the transfer function will not affect the availability or operation of the emergency diesel generators.

4.0 TECHNICAL ANALYSIS

The following is a description and basis of the fast and slow transfer design at RBS for powering the NNS-SWG1A or NNS-SWG1B 13.8 kV buses from station service transformer STX-XNS1C (main generator as the power source). The RBS Division III safety related bus E22-S004 is normally powered through non-safety related bus NNS-SWG1C. NNS-SWG1C can be powered by either NNS-SWG1A or NNS-SWG1B.

The current procedures do not permit energizing E22-S004 via STX-XNSIC during power operations.

The design scheme discussed in sections 4.2.1 and 4.2.2 shows that RBS has two transfer schemes (fast and slow) that permit the automatic transfer from STX-XNS1 C to offsite power supplies provided through transformers RTX-XSR1 C and RTS-XSR1 D, to ensure power is restored to the bus per design requirements.

4.1.1 Offsite Power Supply:

Safety related buses (Division I, ENS-SWG1A, Division II, ENS-SWG1B and Division Ill; E22-S004) are powered via two independent offsite power supplies. Offsite power supplies for Division I and II buses are via preferred station service transformers RTX-XSR1 C and RTX-XSR1 D, respectively. Current operating procedures ensure correct breaker alignment.

The Division III safety related bus is powered by non-safety related bus NNS-SWG1C.

Transformers RTX-XSR1 C and RTX-XSR1 D can also power non-safety related buses NNS-SWG1A and NNS-SWG1B, respectively. NNS-SWG1C can be powered by either of these two non-safety related buses. Thus by powering NNS-SWG1 C from either NNS-SWGIA or NNS-SWG1B, the Division III safety related bus, E22-S004, canobe powered by either RTX-XSR1 C or RTX-XSR1 D, respectively.

RBG-47191 Page 5 of 12 With offsite power supplied through transformers RTX-XSR1 C or RTX-XSR1 D, the power to the safety related buses is separated as follows:

Division I and Division II safety related buses are powered from separate preferred station service transformers.

Division III is powered from the same transformers as Division I or Division II with the power supplied through the non safety bus, as described above.

The control of these alignments is contained in current plant procedures.

The requested option to supply the Division III from onsite power when automatic transfer is available will allow the power to be transferred from the main generator to the appropriate preferred station service transformer. This transfer will not change the alignments identified above after the transfer is complete.

4.1.2 Generator as Power Supply:

Normal Station Service Transformer, STX-XNS1C, can power non-safety related buses NNS-SWG1A and NNS-SWG1 B. This allows the main generator to power the Division III safety related bus, E22-S004. There is a provision to power the Division I and/or II safety related buses via NNS-SWG1A and NNS-SWG1 B. However current restrictions allow this configuration only during Modes 4 and 5 of operations per plant operating procedures. Hence, ENS-SWG1A/1B cannot be powered by the main generator, as the plant will be shutdown during Modes 4 and 5.

This request addresses conditions when offsite power is available through RTX-XSR1C and RTX-XSR1 D, when a transfer from STX-XNS1 C to the offsite power sources will restore power to Division III safety related bus E22-S004 before a loss of voltage signal on the bus initiates the safety related diesel generator.

4.2.1 Fast Transfer Scheme:

The fast transfer scheme is designed to allow an automatic transfer of power from STX-XNS1 C to either RTX-XSR1 C or RTX-XSR1 D depending on breaker alignments. A fast transfer is initiated by tripping of STX-XNS1 C supply breakers NNS-ACB06 and NNS-ACB 14 on any of the following signals: main generator protection circuits including, ground detection, phase imbalance and reverse power.

Fast transfer scheme is blocked when either the Standby Service Water Pump (SWP-P2C) or the High Pressure Core Spray Pump (E22-CO01) is running. This block protects these two critical safety related motors due to the resultant volts/hertz for HPCS and SWP-C motors is above the ANSI C50.41 guidance against damage during the transfer scheme.

There is other station equipment protection which blocks on the fast transfer scheme.

These blocks are not part of the fast transfer scheme but are part of the distribution RBG-47191 Page 6 of 12 protection and are indications of a loss of the power source regardless of the need to transfer. These equipment protection features are in the current design with no revisions resulting from the transfer function. These blocks include:

1. Unit Electrical Protection Trip (Time Delay; 0.15 sec).

2. Main Generator Primary Electrical Protection Trip (Time Delay; 0.15 sec):

3. Main Generator Backup Electrical Protection Trip (Time Delay; 0.15 sec):

4. Preferred station service transformer voltage less than 90% (No time delay).

5. STX-XNS1C ground and phase overcurrent (No time delay).

6. NNS-SWG1A/1B bus undervoltage (less than 80% with a 2 seconds time delay).

7. Manual trip of Generator supply breakers (No time delay).

If any of the above blocks are enabled the fast transfer is not completed. The slow transfer function, as described below, will be initiated.

4.2.2 Slow Transfer Scheme:

The slow transfer scheme ensures automatic transfer of power from STX-XNS1 C to RTX-XSR1 C/1 D. The slow transfer scheme is initiated when a loss of voltage signal (<

80% Voltage + 2 second time delay) is detected on the NNS-SWG1A and/or NNS-SWG1 B buses. The transfer scheme will not be completed unless the voltage on the bus drops down to below 25% of rated voltage on these buses.

A slow transfer will not damage the HPCS or the SWP motor as it requires voltage to drop below 25%. The result is volts/hertz for HPCS and SWP-C motors is within the ANSI 050.41 guidance and does not require a block of the transfer.

Other blocks for the slow transfer scheme are; preferred station service transformer voltage less than 90% and STX-XNSIC overcurrent and ground trip. These are protective blocks to ensure that offsite power would be available and protect the offsite power by preventing transfer if there is a faulted bus. These equipment protection features are in the current design with no revisions resulting form the transfer function.

4.3 Interface with Loss of Voltage relay on E22-S004:

The loss of voltage signal for the safety related bus E22-S004 trips breaker E22-S004-ACB4 after 3 seconds of a loss of voltage detection on E22-S004. The loss of voltage dropout for E22-S004 is set at 70% of nominal bus voltage. Once the bus has less than 70% of nominal bus voltage and 3 seconds have passed the associated Division III emergency diesel generator will be initiated.

For conservatism, it can be assumed that both loss of voltage relays (on NNS-SWG1A/1B and E22-S004) drop out at the same time. Thus, the slow transfer scheme will be completed within 3 seconds as discussed below.

The transfer scheme will result in tripping of loads on NNS-SWG1A, NNS-SWG1B, NNS-SWG1 C, NNS-SWG4A, and NNS-SWG4B. The following breakers do not trip on a RBG-47191 Page 7 of 12 degraded voltage or loss of voltage signal, thus ensuring the safety related bus, E22-S004, is not lost during a slow bus transfer:

1. NNS-SWG1 C breaker-ACB23 / NNS-SWG1 C breaker-ACB24

2. NNS-SWG1A breaker-ACB29 / NNS-SWG 1B breaker-ACB28

3. NNS-SWG1C breaker-ACB25

4. E22-S004 breaker-ACB2

5. E22-S004 breaker-ACB3 Breaker E22-S004-ACB4 and E22-S004-ACB5 trip on a loss of voltage signal after 3 seconds. This time delay is longer than the slow transfer initiation signal.

The slow transfer scheme design is as long as 2.04 seconds, using the longest initiation delay, and will complete prior to 2.67 seconds, shortest diesel generator initiation signal.

Considering breaker switching times, a 30 cycle, or 0.5 sec., margin exists between initiation of slow transfer and initiation of loss of voltage sequence on Div III bus.

This ensures that the E22-S004-ACB4 breaker will not trip during a transfer sequence and therefore, the Division III diesel generator will not start under these conditions.

4.4 New Actions Added By This Request In addition to the surveillance added to SR 3.8.1.8 two actions are proposed to address the possible loss of the automatic transfer ability from on-site power to a powered offsite source.

4.4.1 New ACTION A.2 As identified in Section 2.0 a new action will verify that upon receipt of an automatic transfer initiation the Division III bus will be aligned to a powered offsite source.

This ACTION is further modified by a note that requires verification only if the 22 kV onsite circuit is supplying Division III safety related bus. This note is included because if the Division III bus is aligned to an offsite power source then the automatic transfer feature is not required and therefore the verification of alignment is not required.

The COMPLETION TIME is consistent with the loss of a required offsite circuit.

4.4.2 New ACTION B The new action B will address conditions when it is discovered the automatic transfer function is not functional. In this condition a loss of the automatic transfer function is replaced by configuring the division III power source directly to offsite power. This action will remove the need for the automatic transfer feature.

The COMPLETION TIME requested is based upon the COMPLETION TIMES of the supported systems. The Division III (HPCS) outage time is 14 days as allowed by TS RBG-47191 Page 8 of 12 3.5.1 and the Standby Service Water System pump 2C is 30 days as allowed by TS 3.7.1. The requested COMPLETION TIME of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is conservatively bounded by the allowed outage times of the supported equipment while still requiring prompt realignment. A review of the risk of this configuration is addressed in Section 4.7.

4.5 Procedural controls The configuration for supplying power to Division III will be controlled under the current system operating procedure. This procedure will be modified to include the restriction to ensure the transfer function is operable if the alignment is through transformer STX-XNS1C.

The revised surveillance will be completed and the transfer function will be verified to be operable prior to alignment through transformer STX-XNS1C. This revised surveillance will include both transfer functions. As noted in the proposed change and in the revised surveillance, the automatic transfer function will not be required to be operable if the alignment is through the RTX-XSR1 C or RTX-XSR1 D transformers.

4.6 Equipment Design and Maintenance Rule Impact The components used in the transfer function have been designed to the same requirements of non-safety related 4.16 kV switchgear as the current supply through RTX-XSR1 C and RTX-XSR1 D transformers The components used in the transfer function will be added to the maintenance rule monitoring scope.

4.7 Risk Impact A review of the risk impact crediting the automatic transfer function was performed. The results of this review confirm the inclusion of the automatic transfer function in the RBS PRA model. The RBS PRA does model the transfer (fast or slow) from the normal to the preferred transformers when the safety related busses have power through STX-XNS1 C. Results indicate a negligible impact on risk based on alignment to the STX-XNS1 C normal station service transformer compared to the RTS-XSR1 C(D) preferred station transformers if the transfer function is available.

The results are below the equipment-out-of-service (EOOS) truncation limit of 1 E-09/year used for on-line maintenance risk assessment. Using a more detailed truncation limit of 1 E-1 2/year with an average maintenance unavailability model and an assumption of no severe weather conditions, the decrease in Core Damage Frequency calculated using EOOS for NNS-SWG1A and NNS-SWG1B aligned to STX-XNS1C is 2.2E-1 1/reactor year. This alignment shows a very small risk reduction due to the increase in redundancy in power supplies to NNS-SWG1A(B) due to credit for transfer to the preferred transformers. It is concluded the proposed alignment has a negligible adverse impact on plant risk.

RBG-47191 Page 9 of 12 A review of the risk impact of the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> COMPLETION TIME, in ACTION B, to restore Division III power source to the preferred station service transformers was performed.

This was evaluated by assuming the failure or unavailability of the transfer function between STX-XNS1 C and the preferred station transformers; it was assumed that Division 3 (NNS-SWG1C) was aligned to Division 1 (NNS-SWG1A) since the Div.1 bus has a higher PRA risk importance. Using the EOOS on-line risk assessment tool with the average maintenance model, average weather conditions, and the E-09 truncation used for on-line risk assessments, the impact on CDF of unavailability of the transfer function is 6.7E-07/rx.year. This corresponds to an internal event incremental core damage probability (ICDP) of 9.2E-10 associated with the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> completion time, a very small and acceptable incremental risk. This supports the proposed 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> completion time based upon allowed outage times of supported equipment while still requiring prompt realignment.

4.8 Conclusion As described above, the design of the transfer function will ensure the power supply for Division III electrical power to the safety related E22-S004 bus will re-align from the main generator through STX-XNS1 C to offsite power through RTX-XSR1 C or RTX-XSR1 D prior to the start of the associated standby diesel generator. This transfer will also complete prior to the re-powering of the E22-S004 bus assumed in the associated accident analysis. As a result, this transfer will complete within the bounds of the safety analysis. This transfer function is automatic with no dependence on operator actions.

If offsite power is not available, the transfer function will not inhibit the initiation and powering of the E22-S004 bus with the associated diesel generator, as assumed in the associated accident analysis. Therefore, with the automatic transfer function in place, the current ECCS analysis remains valid.

The transfer function is designed and maintained with the same standards as the current power supply through RTX-XSR1 C or RTX-XSR1 D. This function will be included in the 10 CFR 50.65, Maintaince Rule, program ensuring proper monitoring and maintenance.

New ACTION A.2 will ensure a loss of an offsite power source will not result in the Division III bus being unable to transfer to a powered offsite source.

New ACTION B will ensure a loss of the automatic transfer feature is addressed by aligning the Division III bus to an offsite source. This action will remove the need for the automatic transfer feature.

The addition to surveillance requirement SR 3.8.1.9 will ensure the operability of the transfer functions thereby supporting the use of the onsite power source with the ability to transfer to an offsite power source as needed.

RBG-47191 Page 10 of 12

5.0 REGULATORY ANALYSIS

5.1 Applicable Regulatory Requirements/Criteria The design discussed within this document is within the requirements of Regulatory Guide 1.75. This guide describes a method acceptable to the NRC staff of complying with IEEE Std 279 1971 and Criteria 3, 17, and 21 of Appendix A to 10 CFR Part 50 with respect to the physical independence of the circuits and electric equipment comprising or associated with the Class 1 E power system, the protection system, systems actuated or controlled by the protection system, and auxiliary or supporting systems that must be operable for the protection system and the systems it actuates to perform their safety-related functions.

5.2 No Significant Hazards Consideration A change is proposed to the River Bend Station Technical Specification (TS) 3.8.1; AC Sources - Operating, Surveillance Requirement (SR) 3.8.1.8.

Entergy 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 change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed change revises the Technical Specification Surveillance Requirements to allow power for emergency systems to be supplied from onsite power prior to event initiation. This power supply will be transferred to the current accepted offsite power source if the main generator is no longer available. The proposed Surveillance Requirement is to confirm the automatic transfer function.

The proposed changes do not involve a change in the design requirements of the electrical power systems, including the emergency power systems. The plant will continue to operate within acceptable parameters (electrical loading, etc.) The proposed changes do not change the function of plant equipment, or affect the response of emergency power systems.

The proposed changes do not involve a change in the design basis initiators for loss of offsite power to the emergency power systems. The proposed change utilizes existing components and circuits. The change will add a new surveillance requirement to confirm the design function operation.

The proposed change does not impact other design basis accident initiators or analyzed events or assumed mitigation of accident or transient events.

RBG-47191 Page 11 of 12 The proposed change does not involve a change to the consequences of a design basis event as described in the Safety Analysis Report. Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

2.

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

Response: No.

The proposed change revises the Technical Specification surveillance requirements to confirm operation of existing components and circuits.

The proposed changes do not involve a change in the design basis initiators for loss of offsite power to the emergency power systems.

The proposed changes do not involve a change in the design requirements of the electrical power systems, including the emergency power systems. The proposed changes do not change the function of plant equipment, nor do they affect the response of emergency power systems.

The proposed changes do not involve a change in the operational limits or physical design of the electrical power systems, particularly the emergency power systems. The proposed changes do not change the design function or operation of plant equipment, nor do they introduce any new failure mechanisms.

This change will implement surveillance requirements to confirm the design function operation.

The transfer function components supporting the safety-related buses have been designed to applicable quality standards and design criteria. As such, no new failure modes are being introduced. The plant equipment will continue to respond in accordance with the design and analyses, and no malfunction of a new or different type is being introduced by the proposed changes.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.

3.

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

Response: No.

The proposed change revises the Technical Specification surveillance requirements. The proposed changes do not involve a change in the operational limits or the response of that equipment if it is called upon to operate.

The performance capability of the emergency diesel generators will not be affected. The plant will continue to operate within acceptable parameters (electrical loading, etc.)

RBG-47191 Page 12 of 12 In addition, administrative controls will ensure there are adequate administrative controls are in place to ensure the plant configuration remains as evaluated.

The results of the PRA performed to quantitatively assess the risk impact of this change indicate there is a minimal risk impact.

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

Based on the above, Entergy concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92, and, accordingly, a finding of "no significant hazards consideration" is justified.

5.3 Environmental Considerations 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 (9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6.0 Precedence Similar surveillance requirements are currently contained on the Technical Specifications of Indian Point Energy Center Unit 2. This unit contains an allowance to limit the operability of the automatic transfer function to configurations where the transfer function is needed to connect to offsite power.

7.0 References

1. RBS USAR Figure 8.1-6

2. RBS USAR Figure 8.3-3 RBG-471911 Technical Specification Markup RBG-47191 Page 1 of 8 Insert 1 - LCO NOTE NOTE The automatic transfer function for the Division III 4.16 kV system buses shall be OPERABLE whenever the 22 kV onsite circuit is supplying Division III safety related bus E22-S004 from normal power transformer STX-XNS1 C.

RBG-47191 Page 2 of 8 Insert 2 - CONDITION "A" ACTION and COMPLETION TIME.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One required offsite circuit inoperable.

A.1 Perform SR 3.8.1.1 for OPERABLE required offsite circuit.

AND NOTE--------

Verification is only required if 22 kV onsite circuit is supplying Division III safety related bus E22-S004 from normal power transformer STX-XNS1C.

A.2 Verify E22-S004 is aligned to transfer to the preferred station transformer powered by the OPERABLE offsite circuit.

AND A.3 Restore required offsite circuit to OPERABLE status.

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from discovery of two divisions with no offsite power AND 17 days from discovery of failure to RBG-47191 Page 3 of 8 Insert 3 - New CONDITION "B" and COMPLETION TIME.

Note, the remaining conditions will be re-numbered.

B.

Automatic transfer function B.1 Restore Division III power 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> not OPERABLE source to the preferred station service transformers Insert 4 - Revised SR 3.1.8.1.8 SURVEILLANCE FREQUENCY SR 3.8.1.8

---

NOTE --------------------------------

1. This Surveillance shall not be performed in MODE 1 or 2. However, credit may be taken for unplanned events that satisfy this SR.

2. SR3.8.1.8.b is only required to be met if 22 kV onsite circuit is supplying Division III safety related bus E22-S004 from normal power transformer STX-XNS1C.

a. Verify manual transfer of unit power supply from the normal offsite circuit to required alternate offsite circuit.

24 months

b.

Verify automatic transfer of bus E22-S004 through NNS-SWG1A or NNS-SWG1B from the22 kV onsite circuit to required 24 months offsite circuit.

RBG-47191 Page 4 of 8 AC Sources-Operating 3.8.1 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources-Operating LCO 3.8.1 The following AC electrical power sources shall be OPERABLE:

a.

Two qualified circuits between the offsite transmission network and the onsite Class 1 E AC Electric Power Distribution System; and

b.

Three diesel generators (DGs).

APPLICABILITY:

MODES 1, 2, and 3.

-NOTES.

1. Division III AC electrical power sources are not required to be OPERABLE when High Pressure Core Spray System and Standby Service Water System pump 2C are inoperable.

2. Insert 1 ACTIONS

-NOTE-LCO 3.0.4.b is not applicable to DGs.

CONDITION REQUIRED ACTION COMPLETION TIME Insert 2 Insert 2 Insert 2 ino~p*a OPERABLE required offsite circuit.

AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND (continued)

RIVER BEND 3.8-1 Amendment No. 84,1-RBG-471 91 Page 5 of 8 AC Sources-Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME 2-Rerctere FcqUircd effsite -- 7-24i~wf&

circuit to OPERABLE status.

AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from discovery of two divisions with no offsite power AN..DD

-47_ da ys from disc of failure to met LCO*'

Insert 3 Insert 3 Insert 3 One required DG

a. 1 Perform SR 3.8.1.1 for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> C.

inoperable.

OPERABLE required offsite circuit(s).

AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND 0.2 Declare required 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from discovery feature(s), supported by of Condition B the inoperable DG, concurrent with inoperable when the inoperability of redundant required redundant required feature(s) are feature(s) inoperable.

AND (continued)

RIVER BEND 3.8-2 Amendment No. 84, 1 RBG-47191 Page 6 of 8 AC Sources-Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C 4. (continued)

B.3.1 Determine OPERABLE 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> DG(s) are not inoperable due to common cause failure.

OR B.3.2 Perform SR 3.8.1.2 for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> OPERABLE DG(s).

AND B.4 Restore required DG to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> from OPERABLE status.

discovery of an inoperable Division III DG AND 14 days AND 17 days from discovery of failure to meet LCO D G. Two required offsite circuits C.1 Declare required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from inoperable, feature(s) inoperable discovery of when the redundant Condition C required feature(s) are concurrent with inoperable.

inoperability of redundant required feature(s)

AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> C.2 Restore one required offsite circuit to OPERABLE status.

(continued)

RIVER BEND 3.8-3 Amendment No. 84, 2-25 RBG-47191 Page 7 of 8 AC Sources-Operating 3.8.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E Q. One required offsite circuit

-.--------- NOTE----------

inoperable.

Enter applicable Conditions and Required Actions of AND LCO 3.8.9, "Distribution Systems-Operating," when any One required DG division is de-energized as a inoperable, result of Condition D.

D.1 Restore required offsite 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> circuit to OPERABLE status.

OR D.2 Restore required DG to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> OPERABLE status.

F E-. Two required DGs E.1 Restore one required 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> inoperable.

DG to OPERABLE status.

OR 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if Division III DG is inoperable G F. Required Action and F.1 Be in MODE 3.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Associated Completion Time of Condition A, B, C, AND D, or E not met.

F.2 Be in MODE 4.

36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> H G. Three or more required AC G.1 Enter LCO 3.0.3.

Immediately sources inoperable.

I RIVER BEND 3.8-4 Amendment No. 84 RBG-47191 Page 8 of 8 AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.7 NOTE- -

All DG starts may be preceded by an engine prelube period.

Verify each DG starts from standby conditions and 184 days achieves:

a.

For DG 1A and DG 1B:

1.

In _< 10 seconds, voltage > 3740 V and frequency 2t 58.8 Hz; and

2.

Steady state voltage _> 3740 V and

< 4580 V and frequency Ž_ 58.8 Hz and

< 61.2 Hz.

b.

For DG 1C:

1.

Maximum of 5400 V, and 66.75 Hz, and

2.

In < 13 seconds, voltage Ž_ 3740 V and frequency > 58.8 Hz; and

3.

Steady state voltage Ž_ 3740 V and

_< 4580 V and frequency >_ 58.8 Hz and

_< 61.2 Hz.

Insert 4 Insert 4 SR 3.8.1.8 NOTE or 2.

o credit may be taken for unplanned events that satisfy Verify manual transfer of unit power suppply from ýthe ths normal offsite circuit to required alternate offsite circuit (continued)

RIVER BEND 3.8-7 Amendment No. 81 121 465, 108 -

RBG-47191 Technical Specification BASES Mark-up (For Information Only)

RBG-47191 Page 1 of 14 Transformer BASES inserts Insert 1 - LCO note LCO 3.8.1 is modified by a Note which requires the automatic transfer function, used to power Division III E22-S004 bus from normal power transformer STX-XNS1 C, to be OPERABLE whenever the 22 kV onsite circuit is being used to supply Division III safety related bus. This is necessary to ensure that Division III safety related bus E22-S004 will be transferred automatically from the 22 kV onsite circuit to preferred offsite circuit following a plant trip.

Insert 2 - CONDITION "A.2" ACTION and COMPLETION TIME.

Action A.2, will require aligning the 4.16 kV Division III safety related bus E22-S004, powered from NNS-SWG1A or NNS-SWG1B, to swap to the preferred station transformer, RTS-XNS1 C or RTS-XNS1 D which is energized. A Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> ensures that the offsite circuit is configured to support the required of ESF functions for Division III safety related bus E22-S004 through NNS-SWG1A or NNS-SWG1B 4.16 kV buses The ACTION is modified by a note to limit the REQUIRED ACTION to when the 22 kV onsite power circuit is being used to feed Division III E22-S004 bus from transformer STX-XNS1C. This note is included because if the Division III bus is aligned to an offsite power source then the automatic transfer feature is not required and therefore the verification of alignment is not required.

Insert 3 - New CONDITION "B" ACTION and COMPLETION TIME. Note, the remaining conditions will be re-numbered.

Action B, applies when the auto transfer function from the 22 kV onsite circuit to the 230 kV offsite circuit through transformers RTS-XNS1 C or RTS-XNS1 D is found inoperable. This action will require placing the 4.16 kV Division III safety related bus E22-S004, powered from NNS-SWG1A or NNS-SWG1B, through transformers RTS-XNS1C or RTS-XNS1D. This action will ensure the automatic transfer feature is no longer required and the 230 kV offsite circuit is supplying 4.16 kV buses NNS-SWG1A or NNS-SWG1B through transformers RTS-XNS1C or RTS-XNS1D.

The requested COMPLETION TIME of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is conservatively bounded by the allowed outage times of the supported equipment.

RBG-47191 Page 2 of 14 Insert 4 - SR 3.8.1.8 Notes Note 2 specifies that this SR is required to be met only when the 22 kV onsite circuit is supplying 4.16 kV Division III safety related bus E22-S004, via transformer STX-XNS1C and non-safety related switch gear NNS-SWG1SA and NNS-SWG1 B. This is acceptable because the feature being tested does not perform a safety function if the 230 kV offsite circuit is already supplying 4.16 kV buses NNS-SWG1A or NNS-SWG1B through transformers RTS-XNS1C or RTS-XNS1D.

Insert 5 -

Verification that 4.16 kV Division III safety related bus E22-S004 through NNS-SWG1A or NNS-SWG1 B will auto transfer from the 22 kV onsite circuit to the 230 kV offsite circuit through transformers RTS-XNS1 C or RTS-XNS1 D following a loss of voltage on 22 kV onsite bus is needed to confirm the OPERABILITY of a function assumed to operate to provide offsite power to Division III safety related bus E22-S004 following a trip of the main generator. (Note that when the main generator trips on over-frequency, the transfer is blocked by an over-frequency transfer interrupt circuit provided for bus protection of out of phase transfer.)

An actual demonstration of this feature requires the tripping the main generator while the reactor is at power with the main generator supplying Division III safety related bus E22-S004. Credit may be taken for planned plant trips or for unplanned events that satisfy this SR. Other than planned plant trips or unplanned events, Note 1 specifies that this SR is not normally performed in MODE 1 or 2 because performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, unit safety systems. This restriction from normally performing the Surveillance in MODE 1 or 2 is further amplified to allow the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced.

In lieu of actually initiating a circuit transfer, this SR may be satisfied by testing that adequately shows the capability of the transfer. This transfer testing may include any sequence of sequential, overlapping, or total steps so that the entire transfer sequence is verified.

RBG-47191 Page 3 of 14 AC Sources - Operating B 3.8.1 BASES LCO The AC sources in one division must be separate and independent (to the (continued) extent possible) of the AC sources in the other division(s). For the DGs, the separation and independence are complete. For the offsite AC sources, the separation and independence are to the extent practical.

Insert 1 APPLICABILITY The AC sources are required to be OPERABLE in MODES 1, 2, and 3 to ensure that:

a.

Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and

b.

Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.

A Note has been added taking exception to the Applicability requirements for Division Ill sources, provided the HPCS System and SSW pump 2C is declared inoperable. This exception is intended to allow declaring of the HPCS System inoperable either in lieu of declaring the Division III source inoperable, or at any time subsequent to entering ACTIONS for an inoperable Division III source. This exception is acceptable since, with the HPCS System inoperable and the associated ACTIONS entered, the Division III AC sources provide no additional assurance of meeting the above criteria.

AC power requirements for MODES 4 and 5 are covered in LCO 3.8.2, "AC Sources - Shutdown."

ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.

There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

A.. 1 To ensure a highly reliable power source remains, it is necessary to verify the availability of the remaining required offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in the Required Action not met. However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for two offsite circuits inoperable, is entered.

(continued)

RIVER BEND B 3.8-4 Revision No. 133 RIVER BEND B 3.8-4 Revision No. 133 RBG-47191 Page 4 of 14 AC Sources - Operating B 3.8.1 BASES ACTIONS Insert 2 (continued)

A.4 3 According to Regulatory Guide 1.93 (Ref. 6), operation may continue in Condition A for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

This Completion Time assumes sufficient offsite power remains to power the minimum loads needed to respond to analyzed events. In the event one or more division is without offsite power, this assumption is not met.

Therefore, the optional Completion Time is specified. Should two (or more) divisions be affected, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is conservative with respect to the Regulatory Guide assumptions supporting a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time for both offsite circuits inoperable. With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the plant safety systems. In this Condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1 E distribution system.

The Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA occurring during this period.

The third Completion Time for Required A~tion A.2 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 14 days. This situation could lead to a total of 17 days, since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 14 days (for a total of 31 days) allowed prior to complete restoration of the LCO. The 17 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 14 day Completion Times means that both (continued)

RIVER BEND B 3.8-5 Revision No. 105 RBG-47191 Page 5 of 14 AC Sources - Operating B 3.8.1 BASES ACTIONS A.42 3 (continued)

Completion Times apply simultaneously, and the more restrictive must be met.

The Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time the LCO was initially not met, instead of at the time that Condition A was entered.

Insert 3 C

.1 To ensure a highly reliable power source remains, it is necessary to verify the availability of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable.

Upon offsite circuit inoperability, additional Conditions must then be entered.

C 8.2 Required Action B.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related divisions (i.e., single division.

systems are not included, although, for this Required Action, Division Ill is considered redundant to Division I and II Emergency Core Cooling System (ECCS)). Additionally, the Division III powered SSW pump 2C is considered redundant to SSW pumps 2B and 2D powered from Division II. Redundant required features failures consist of inoperable features associated with a division redundant to the division that has an inoperable DG.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:

(continued)

RIVER BEND 6 3.8-6 Revision No. 0 RBG-47191 Page 6 of 14 AC Sources - Operating B 3.8.1 BASES ACTIONS C -. 2 (continued)

a.

An inoperable DG exists; and

b.

A required feature on another division is inoperable.

If, at any time during the existence of this Condition (one DG inoperable),

a required feature subsequently becomes inoperable, this Completion Time begins to be tracked.

Discovering one required DG inoperable coincident with one or more required support or supported features, or both, that are associated with the OPERABLE DG(s), results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

The remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature.

Additionally, the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period.

C 4.3.1 and C 4.3.2 Required Action B.3.1 provides an allowance to avoid unnecessary testing of OPERABLE DGs. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on other DG(s),

the other DG(s) are declared inoperable upon discovery, and Condition E and potentially Condition G of LCO 3.8.1 is entered. Once the failure is repaired, and the common cause failure no longer exists, Required Action B.3.1 (continued)

RIVER BEND B 3.8-7 Revision No. 0 RBG-47191 Page 7 of 14 AC Sources - Operating B 3.8.1 BASES ACTIONS C,..3.1 and C 4.3.2 (continued) is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s), performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of those DG(s).

In the event the inoperable DG is restored to OPERABLE status prior to completing either B.3.1 or B.3.2, the Condition Report Program will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> constraint imposed while in Condition B.

According to Generic Letter 84-15 (Ref. 7), 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is reasonable time to confirm that the OPERABLE DG(s) are not affected by the same problem as the inoperable DG.

C 9.4 In Condition B, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E distribution system. Although Condition B applies to a single inoperable DG, several Completion Times are Specified for this Condition. The first completion time applies to an inoperable Division III DG. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period. This Completion Time begins only "upon discovery of an inoperable Division III DG" and, as such, provides an exception to the normal "time zero" for beginning the allowed outage time "clock" (i.e., for beginning the clock for an inoperable Division Ill DG when Condition B may have already been entered for another equipment inoperability and is still in effect).

The second Completion Time (14 days) applies to an inoperable Division I or Division II DG and is risk-informed allowed out-of-service time (AOT) based on plant specific risk analysis. The extended AOT would typically be use for voluntary planned maintenance or inspections but can also be used for corrective maintenance. However, use of the extended AOT for voluntary planned maintenance should be limited to once within an 18-month period for each DG (Division I and Division II). Additional contingencies are to be in place for any extended AOT duration (greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and up to 14 days) as follows:

1. An DG extended AOT will not be entered for voluntary planned maintenance purposes if severe weather conditions are expected.

(continued)

RIVER BEND B 3.8-8 Revision No. 143 RBG-47191 Page 8 of 14 AC Sources - Operating B 3.8.1 BASES ACTIONS C

..4 (continued)

2. The condition of the offsite power supply and switchyard, including transmission lines and ring bus breakers, will be evaluated.

3. No elective maintenance will be scheduled within the switchyard that would challenge offsite power availability during the proposed extended DG AOT.

4. Operating crews will be briefed on the DG work plan, with consideration given to key procedural actions that would be required in the event of a LOOP or SBO.

5. High pressure injection systems will not be taken OOS for maintenance while DG Division I or II is out of service for extended maintenance.

The third Completion Time for Required Action BA4 established a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

This situation could lead to a total of 17 days, since initial failure to meet the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (for a total of 20 days) allowed prior to complete restoration of the LCO. The 17 day Completion Time provides a limit on the time allowed in a specified (continued)

RIVER BEND B 3.8-8a Revision No. 105 RBG-47191 Page 9 of 14 AC Sources - Operating B 3.8.1 BASES ACTIONS C 1,.4 (continued) condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the Completion Times means that the three Completion Times apply simultaneously, and the most restrictive Completion Time must be met.

As in Required Action B.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time the LCO was initially not met, instead of the time Condition B was entered.

D 0.1 and 0 Q.2 Required Action C.1 addresses actions to be taken in the event of concurrent failure of redundant required features. Required Action C.1 reduces the vulnerability to a loss of function. The rationale for the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is that Regulatory Guide 1.93 (Ref. 6) allows a Completion Time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for two required offsite circuits inoperable, based upon the assumption that two complete safety divisions are OPERABLE. When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is appropriate.

These features are designed with redundant safety related divisions (i.e.,

single division systems are not included in the list, although, for this Required Action, Division III is considered redundant to Division I and II ECCS. Additionally, the Division III powered SSW pump 2C is considered redundant to SSW pumps 2B and 2D powered from Division II).

Redundant required features failures consist of any of these features that are inoperable, because any inoperability is on a division redundant to a division with inoperable offsite circuits.

The Completion Time for Required Action C.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required (continued)

RIVER BEND B 3,8-9 Revision No. 105 RBG-47191 Page 10 of 14 AC Sources - Operating B 3.8.1 BASES ACTIONS D G.1 and DQ.2 (continued)

Action, the Completion Time only begins on discovery that both:

a.

All required offsite circuits are inoperable; and

b.

A required feature is inoperable.

If, at any time during the existence of this Condition (two offsite circuits inoperable), a required feature subsequently becomes inoperable, this Completion Time begins to be tracked.

According to Regulatory Guide 1.93 (Ref. 6), operation may continue in Condition C for a period that should not exceed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This level of degradation means that the offsite electrical power system does not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded. This level of degradation generally corresponds to a total loss of the immediately accessible offsite power sources.

Because of the normally high availability of the offsite sources, this level of degradation may appear to be more severe than other combinations of two AC sources inoperable that involve one or more DGs inoperable.

However, two factors tend to decrease the severity of this degradation level:

a.

The configuration of the redundant AC electrical power system that remains available is not susceptible to a single bus or switching failure; and

b.

The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite AC source.

With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety (continued)

RIVER BEND B 3.8-10 Revision No. 0 RBG-47191 Page 11 of 14 AC Sources - Operating B 3.8.1 BASES ACTIONS D Q.1 and D G.2 (continued) analysis. Thus, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time provides a period of time to effect restoration of one of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria.

According to Regulatory Guide 1.93 (Ref. 6), with the available offsite AC sources two less than required by the LCO, operation may continue for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If two offsite sources are restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, unrestricted operation may continue. If only one offsite source is restored within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, power operation continues in accordance with Condition A.

E 4.1 and E 9.2 Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition D are modified by a Note to indicate that when Condition D is entered with no AC source to any division, Actions for LCO 3.8.9, "Distribution Systems-Operating," must be immediately entered. This allows Condition D to provide requirements for the loss of the offsite circuit and one DG without regard to whether a division is de-energized. LCO 3.8.9 provides the appropriate restrictions for a de-energized division.

According to Regulatory Guide 1.93 (Ref. 6), operation may continue in Condition D for a period that should not exceed 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In Condition D, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the reliability of the power systems in this Condition may appear higher than that in Condition C (loss of both required offsite circuits). This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a DBA occurring during this period.

(continued)

RIVER BEND B 3.8-11 Revision No. 0 RBG-47191 Page 12 of 14 AC Sources - Operating B 3.8.1 BASES ACTIONS F.E1 (continued)

With two DGs inoperable, there is one remaining standby AC source.

Thus, with an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions.

Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown (the immediate shutdown could cause grid instability, which could result in a total loss of AC power). Since any inadvertent generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.

According to Regulatory Guide 1.93 (Ref. 6), with both DGs inoperable, operation may continue for a period that should not exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This Completion Time assumes complete loss of onsite (DG) AC capability to power the minimum loads needed to respond to analyzed events. In the event Division III DG in conjunction with Division I or II DG is inoperable, with Division I or II remaining, a significant spectrum of breaks would be capable of being responded to with onsite power. Even the worst case event would be mitigated to some extent-an extent greater than a typical two division design in which this condition represents complete loss of onsite power function. Given the remaining function, a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is appropriate. At the end of this 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, Division III systems could be declared inoperable (see Applicability Note) and this Condition could be exited with only one required DG remaining inoperable. However, with a Division I or II DG remaining inoperable and the HPCS declared inoperable, a redundant required feature failure exists, according to Required Action B.2.

(continued)

RIVER BEND B 3.8-12 Revision No. 0 RBG-47191 Page 13 of 14 AC Sources - Operating B 3.8.1 BASES ACTIONS (continued)

G r--.1 and G -. 2 If the inoperable AC electrical power sources cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and to MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

H G.1 Condition G corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.

SURVEILLANCE REQUIREMENTS The AC sources are designed to permit inspection and testing of all important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, GDC 18 (Ref. 8). Periodic component tests are supplemented by extensive functional tests during refueling outages under simulated accident conditions. The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of Regulatory Guide 1.9 (Ref. 3), Regulatory Guide 1.108 (Ref. 9), and Regulatory Guide 1.137 (Ref. 10).

Where the SRs discussed herein specify voltage and frequency tolerances, the minimum and maximum steady state output voltage of 3740 V and 4580 V respectively, are equal to +/- 10% of the nominal 4160 V output voltage. The specified minimum and maximum frequencies of the DG of 58.8 Hz and 61.2 Hz, respectively, are equal to

+/- 2% of the 60 Hz nominal frequency. The specified steady state voltage and frequency ranges are derived from the recommendations given in Regulatory Guide 1.9 (Ref. 3).

(continued)

RIVER BEND B 3.8-13 Revision No. 0 RBG-47191 Page 14 of 14 AC Sources -- Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.7 REQUIREMENTS See SR 3.8.1.2 SR 3.8.1.8 Transfer of each 4.16 kV ESF bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit. This SR applies to Divisions 1, 2, and 3. The 24 month Frequency of the Surveillance is based on engineering judgment taking into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems.

Credit may be taken for unplanned events that satisfy this SR. Examples of unplanned events may include:

1)

Unexpected operational events which cause the equipment to perform the function specified by this Surveillance, for which adequate documentation of the required performance is available; and

2)

Post corrective maintenance testing that requires performance of this Surveillance in order to restore the component to OPERABLE, provided the maintenance was required, or performed in conjunction with maintenance required to maintain OPERABILITY or reliability.

Insert 4 Inser 5 (continued)

RIVER BEND B 3.8-18 Revision No. 143 RBG-47191 List of Regulatory Commitments RBG-47191 Page 1 of 1 List of Regulatory Commitments The following table identifies those actions committed to by Entergy in this document.

Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments.

TYPE (Check one)

SCHEDULED ONE-CONTINUING COMPLETION COMMITMENT TIME COMPLIANCE DATE ACTION This section will require revision to include X

Implementation testing of the 4.16 KV normal power supply transfer to preferred power supply.

The changes to the affected TS Bases pages X

Implementation will be incorporated in accordance with the TS Bases Control Program.

The configuration for supplying power to X

Implementation Division III will be controlled under the current system operating procedure. This procedure will be modified to include the restriction to ensure the transfer function is operable if the alignment is through transformer STX-XNS1 C.

The revised surveillance will be completed and X

First alignment the transfer function will be verified to be of Division III to operable prior to alignment through STX-XNS1C transformer STX-XNS1 C. This revised surveillance will include both transfer functions.

The components used in the transfer function X

Implementation will be added to the maintenance rule monitoring scope.