ML12277A308
| ML12277A308 | |
| Person / Time | |
|---|---|
| Site: | River Bend  (NPF-047) |
| Issue date: | 12/05/2012 |
| From: | Wang A Plant Licensing Branch IV |
| To: | Entergy Operations |
| Wang A | |
| References | |
| TAC ME7695 | |
| Download: ML12277A308 (24) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 December 5, 2012 Vice President, Operations Entergy Operations, Inc.
River Bend Station 5485 US Highway 61 N St. Francisville, LA 70775
SUBJECT:
RIVER BEND STATION, UNIT 1 - ISSUANCE OF AMENDMENT RE:
PROPOSED CHANGES TO TECHNICAL SPECIFICATION 3.8.1; "AC SOURCES - OPERATING" (TAC NO. ME7695)
Dear Sir or Madam:
The Commission has issued the enclosed Amendment No. 176 to Facility Operating License No. NPF-47 for the River Bend Station, Unit 1 (RBS). The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated December 8,2011, as supplemented by letters dated July 20 and October 26, 2012.
The amendment revises TS 3.8.1, "AC [Alternating Current1-Sources Operating," to include provisions for testing of the automatic transfer function from the onsite 22 kiloVolt bus to offsite power for Division III and the associated standby service water pump powered by the Division III bus. In Section 4.7, "Risk Impact," of the licensee's December 8, 2011, submittal, the licensee provided probabilistic inSights in support of the amendment request. This is not a risk-informed request and, therefore, the NRC staff did not use this risk impact information in its review and approval of this amendment.
A copy of our related Safety Evaluation is enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.
Sincerely, Ala~ng~r~ger Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-458
Enclosures:
- 1. Amendment No. 176 to NPF-47
- 2. Safety Evaluation cc w/encls: Distribution via Listserv
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 ENTERGY GULF STATES LOUISIANA, LLC AND ENTERGY OPERATIONS, INC.
DOCKET NO. 50-458 RIVER BEND STATION, UNIT 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 176 License No. NPF-47
- 1.
The Nuclear Regulatory Commission (the Commission) has found that:
A.
The application for amendment by Entergy Operations, Inc. (the licensee), dated December 8, 2011, as supplemented by letters dated July 20 and October 26, 2012, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.
The facility will operate in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission; C.
There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and Oi) that such activities will be conducted in compliance with the Commission's regulations; D.
The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.
The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.
- 2
- 2.
Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and Paragraph 2.C.(2) of Facility Operating License No. NPF-47 is hereby amended to read as follows:
(2)
Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 176 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license. EOI shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
- 3.
The license amendment is effective as of its date of issuance and shall be implemented shall be implemented prior to startup from the next refueling outage, currently scheduled for early 2013.
FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation
Attachment:
Changes to the Facility Operating License No. NPF-47 and Technical Specifications Date of Issuance: December 5, 2012
ATTACHMENT TO LICENSE AMENDMENT NO. 176 FACILITY OPERATING LICENSE NO. NPF-47 DOCKET NO. 50-458 Replace the following pages of the Facility Operating License No. NPF-47 and Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by Amendment number and contain marginal lines indicating the areas of change.
Facility Operating License Remove -3 Technical Specifications Remove Insert 3.8-1 3.8-1 3.8-2 3.8-2 3.8-2a 3.8-3 3.8-3 3.8-4 3.8-4 3.8-7 3.8-7
-3 (3)
EOI, pursuant to the Act and 10 CFR Part 70, to receive, possess and to use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Final Safety Analysis Report, as supplemented and amended; (4)
EOI, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (5)
EOI, pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6)
EOI, pursuant to the Act and 10 CFR Parts 30,40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.
C.
This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:
(1)
Maximum Power Level EOI is authorized to operate the facility at reactor core power levels not in excess of 3091 megawatts thermal (100% rated power) in accordance with the conditions specified herein. The items identified in Attachment 1 to this license shall be completed as specified. Attachment 1 is hereby incorporated into this license.
(2)
Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 176 and the Environmental Protection Plan contained in Appendix 8, are hereby incorporated in the license. EOI shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
Amendment No. 176
AC Sources-Operating 3.8.1 3.B ELECTRICAL POWER SYSTEMS 3.B.1 AC Sources-Operating LCO 3.B.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.
The automatic transfer function for the Division 1114.16 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-XNS 1 C.
ACTIONS
*---NOTE--------------*-----------
LCO 3.0A.b is not applicable to DGs.
CONDITION REQUIRED ACTION COMPLETION TIME A.
One required offsite circuit inoperable.
A.1 Perform SR 3.B.1.1 for OPERABLE required offsite circuit.
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 (continued)
RIVER BEND 3.B-1 Amendment No, ~, 176
AC Sources-Operating 3.8.1 ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME A.
(continued)
NOTE--------
Verification is only required if 22 kV onsite circuit is supplying Division III safety related bus E22 5004 from normal power transformer STX-XNS1 C.
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 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 meet Leo 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 (continued) I RIVER BEND 3.8-2 Amendment No. ~, 176
3.8.1 AC Sources-Operating ACTIONS (contlnuedl CONDITION REQUIRED ACTION COMPLETION TIME C.
One required DG inoperable.
C.1 Perform SR 3.8.1.1 for OPERABLE required offsite circuit(s).
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> ANO Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter AND C.2 Declare required feature(s). supported by the inoperable OG.
inoperable when the redundant required feature(s) are inoperable.
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from discovery of Condition C concurrent with inoperabllity of redundant required feature(s)
AND (continued)
RIVER BEND 3.&-2a Amendment No. 176
~
3.B.1 AC Sources-Operating ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME C.
(continued)
C.3.1 Determine OPERABLE DG(s) are not inoperable due to common cause failure.
OR C.3.2 Perform SR 3.8.1.2 for OPERABLE DG(s).
Mill CA Restore required DG to OPERABLE status.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 24 hours 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from discovery of an inoperable DivisIon ill DG AND 14 days AND 11 days from discovery of failure to meetLCO D.
Two required offsite circuits inoperable.
0.1 Declare requIred feature(s) inoperable when the redundant required feature(s) are inoperable.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from discovery of Condition 0 concurrent with inoperability of redundant required feature(s)
AND 0.2 Restore one required oftsite circuit to OPERABLE status.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (contInued)
RIVER BEND 3.8-3 Amendment No. ~, 176
3.B.1 AC Sources-Operating ACTIONS (continued)
CONDITION REQUIRED ACTION COMPLETION TIME E.
One required offsite circuit inoperable.
AND One required DG inoperable.
NOTE-------
Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems-Operating," when any division is de-energized as a result of Condition E.
E.1 Restore required offsite circuit to OPERABLE status.
OR E.2 Restore required DG to OPERABLE status.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 12 hours F.
Two required DGs inoperable.
F.1 Restore one required DG to OPERABLE status.
2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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.
Required Action and Associated Completion Time of Condition A, B, C.
D, E or F not met.
G.1 AND I G.2 Be In MODE 3.
Be in MODE 4.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 36 hours H.
Three or more required AC sources inoperable.
H.1 Enter LCO 3.0.3.
Immediately RIVER BEND 3.8-4 Amendment No. 8+.176
3.8.1 AC Sources-Operating SURVEILLANCE FREQUENCY SR 3.8.1.7 NOTE-Ail DG starts may be preceded by an engine prelube period.
Verify each DG starts from standby conditions and 184 days achieves:
- a.
- 1.
In S 10 seconds, voltage ~ 3740 V and frequency;;:: 58.8 Hz: and
- 2.
Steady state voltage 2 3740 Vand
- 4580 V and frequency 2 58.8 Hz and
- s 61.2 Hz.
- b.
For DG 1C:
- 1.
Maximum of 5400 V, and 66.75 Hz. and
- 2.
In!> 13 seconds. voltage 2 3740 V and frequency 2 58.8 Hz; and
- 3.
Steady state voltage 23740 Vand s 4580 V and frequency ~ 58.8 Hz and
~ 61.2 Hz.
--NOTES-------
- 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.
SR 3.8.1.8.b is only requIred to be met if 22 kV onsile circuit is supplying Division III safety related bus E22-S004 from normal power transformer STX-XNS 1 C.
a, Verify manual transfer of unit power supply from 24 months the normal offsite circuit to required alternate oftsite circuit.
- b.
Verify automatic transfer of bus E22-S004 24 months through NNS-SWG1A or NNS-SWG16 from the 22 kV onsite circuit to required offsite circuit.
(continued)
RIVER BEND 3.8-7 Amendment No. 81 1a1 165 HiS, 176
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 176 TO FACILITY OPERATING LICENSE NO. NPF-47 ENTERGY OPERATIONS. INC.
RIVER BEND STATION, UNIT 1 DOCKET NO. 50-458
1.0 INTRODUCTION
By letter dated December 8, 2011, as supplemented by letters dated July 20 and October 26, 2012 (Agencywide Documents Access and Management System (ADAMS) Accession Nos.
ML11348A237, IVIL12206A002, and ML12318A127, respectively), Entergy Operations, Inc. (the licensee), requested changes to the Technical Specifications (TSs) for River Bend Station, Unit 1 (RBS). The supplemental letters dated July 20 and October 26,2012, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC) staff's original proposed no significant hazards consideration determination as published in the Federal Register on May 1, 2012 (77 FR 25757).
The amendment would revise TS 3.8.1, 'lAC [Alternating Current]- Sources Operating," to include provisions for testing of the automatic transfer function from the onsite 22 kiloVolt bus to offsite power for Division III and the associated standby service water pump powered by the Division III bus.
The licensee proposed adding a TS surveillance requirement (SR) to ensure availability of offsite power after loss of the station 22 kV bus when offsite power remains available. In addition to the above, notes would be added to the limiting condition for operation (LCO) and SRs to require this feature when Division III is powered by onsite power. Additionally, ACTIONS would be added to ensure the transfer capability from onsite to offsite power is maintained when a required offsite power source is lost.
2.0 REGULATORY EVALUATION
Section 182a of the Atomic Energy Act of 1954, as amended (the Act), requires applicants for nuclear power plant operating licenses to incorporate TSs as part of the license. The NRC's regulatory requirements related to the content of TSs are set forth in Section 50.36, "Technical
- 2 specifications," of Title 10 of the Code of Federal Regulations (10 CFR), which states that TSs are required to include items in the following five specific categories related to station operation:
(1) safety limits, limiting safety system settings, and limiting control settings; (2) LCOs; (3) SRs; (4) design features; and (5) administrative controls.
The proposed changes to the TSs discussed in this safety evaluation (SE) are within the SRs category. The regulations in 10 CFR 50.36(c){3), "Surveillance requirements," state that Surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met.
In Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50, General Design Criterion (GDC) 17, "Electric power systems," states that An onsite electric power system and an offsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety. The safety function for each system (assuming the other system is not functioning) shall be to provide su'fficient capacity and capability to assure that (1) specified acceptable fuel design limits and deSign conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents.
The onsite electric power supplies, including the batteries, and the onsite electric distribution system, shall have sufficient independence, redundancy, and testability to perform their safety functions assuming a single failure.
Electric power from the transmission network to the onsite electric distribution system shall be supplied by two physically independent circuits (not necessarily on separate rights of way) deSigned and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. A switchyard common to both circuits is acceptable. Each of these circuits shall be designed to be available in sufficient time following a loss of all onsite alternating current power supplies and the other offsite electric power circuit, to assure that specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded. One of these circuits shall be designed to be available within a few seconds following a loss-of-coolant accident to assure that core cooling, containment integrity, and other vital safety functions are maintained.
Provisions shall be included to minimize the probability of losing electric power from any of the remaining supplies as a result of, or coincident with, the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies.
- 3 In Appendix A to 10 CFR Part 50, GDC 18, "Inspection and testing of electric power systems,"
states that Electric power systems important to safety shall be designed to permit appropriate periodic inspection and testing of important areas and features, such as wiring, insulation, connections, and switchboards, to assess the continuity of the systems and the condition of their components. The systems shall be designed with a capability to test periodically (1) the operability and functional performance of the components of the systems, such as onsite power sources, relays, switches, and buses, and (2) the operability of the systems as a whole and, under conditions as close to design as practical, the full operation sequence that brings the systems into operation, including operation of applicable portions of the protection system, and the transfer of power among the nuclear power unit, the offsite power system, and the onsite power system.
3.0 TECHNICAL EVALUATION
3.1 Proposed TS Changes
3.1.1 Changes to LCO 3.8.1 Notes, Conditions, Required Actions, and Completion Times By letter dated December 8,2011, as supplemented by October 26,2012, the licensee requested the following changes to the TS, which include adding a note to LCO 3.8.1, a note to Required Action A.1, a new Required Action A.2, and a new Condition B and Required Action B.1.
Current LCO 3.8.1 Note states:
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.
Revised LCO 3.8.1 Notes would state:
- 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.
The automatic transfer function for the Division 1114.16 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-XNS1C.
- 4 New Note for LCO 3.8.1 Required Action A.1 would state:
Verification is only required if 22 kV onsite circuit is supplying Division III safety related bus E22-S004 from normal power transformer STX-XNS1C.
New LCO 3.8.1 Required Action A.2 and the associated Completion Time would state:
A.2 Verify E22-S004 is aligned to transfer to the preferred station transformer powered by the OPERABLE offsite circuit.
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 In addition, current LCO 3.8.1 Required Action A.2 would be renumbered as Required Action A.3.
New LCO 3.8.1 Condition B would state:
Automatic transfer function not OPERABLE New LCO 3.8.1 Required Action B.1 would state:
Restore Division III power source to the preferred station service transformers New LCO 3.8.1 Condition B associated Completion Time would state:
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> The remaining current LCO 3.8.1 Conditions B through G and Required Actions B.1 through G.1 would be renumbered as Conditions C through H and Required Actions C.1 through H.1. As a result of renumbering conditions, the following editorial changes were made to the LCO 3.8.1:
Current Completion Time for Required Action C.2 states:
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from discovery of Condition B concurrent with inoperability of redundant required feature(s)
Revised Completion Time for Required Action C.2 would state:
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from discovery of Condition C concurrent with inoperability of redundant required feature(s)
Current Completion Time for Required Action D.1 states:
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from discovery of Condition C concurrent with inoperability of redundant required feature(s)
- 5 Revised Completion Time for Required Action D.1 would state:
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from discovery of Condition D concurrent with inoperabilityof redundant required feature(s)
Current Note to Required Actions E.1 and E.2 states:
Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems-Operating," when any division is de-energized as a result of Condition D.
Revised Note to Required Actions E.1 and E.2 would state:
Enter applicable Conditions and Required Actions of LCO 3.8.9, "Distribution Systems-Operating," when any division is de-energized as a result of Condition E.
Current Condition G states:
Required Action and Associated Completion Time of Condition A, S, C, D, or E not met.
Revised Condition G would state:
Required Action and Associated Completion Time of Condition A, S, C, D, E or F not met.
3.1.2 Changes to SR 3.8.1.8 As shown below, the changes include an additional requirement for SR 3.8.1.8 and adding a note to SR 3.8.1.8.
Current SR 3.8.1.8, at a frequency of 24 months, states:
Verify manual transfer of unit power supply from the normal offsite circuit to required alternate offsite circuit.
Revised SR 3.8.1.8, at a frequency of 24 months, would state:
- a.
Verify manual transfer of unit power supply from the normal offsite circuit to required alternate offsite circuit.
- b.
Verify automatic transfer of bus E22-S004 through NNS-SWG1A or NNS-SWG1 S from the 22 kV onsite circuit to required offsite circuit.
- 6 Current SR 3.8.1.8 Note states:
This Surveillance shall not be performed in MODE 1 or 2. However, credit may be taken for unplanned events that satisfy this SR.
Revised SR 3.8.1.8 Notes would state:
- 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.
SR 3.8.1.8.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.
3.2
NRC Staff Evaluation
The NRC staff has reviewed the licensee's regulatory and technical analyses in support of its license amendment request (LAR), which are described in Sections 4.0 and 5.0 of Attachment 1 of the LAR. A detailed description of the RBS electric power system is contained in Chapter 8 of the RBS Updated Safety Analysis Report (USAR). Sections 8.1 and 8.3 of the RBS USAR contain detailed information on the current transformer design and distribution configuration.
The preferred AC power supply can provide power for all station auxiliary loads. This includes the maximum operational combination of full load power, startup power, hot standby maintenance power, shutdown power, and the safety-related loads. Preferred power is taken from two physically and electrically independent 230 kV lines originating in the onsite 230 kV substation. A 230 kV line terminating at transformer yard 1 energizes transformers 1 RTX-XSR 1 E and 1 RTX-XSR 1 C. A 230 kV line terminating at the transformer yard 2A energizes transformers 1RTX-XSR1F and 1RTX-XSR1D.
The normal AC power supply consists of three normal station service transformers energized by isolated phase bus duct from the generator terminals, to include 1STX-XNS1C. The normal AC power supply can provide electrical power for all station auxiliary loads when the main generator is operating.
Each of the two normal in-station 4.16 kV buses, 1 NNS-SWG1A and 1 NNS-SWG1 B, are fed from either the normal station service transformer, 1 STX-XNS 1 C, or from their associated preferred station service transformers, 1 RTX-XSR 1 C and 1 RTX-XSR 1 D, respectively.
According to the RBS USAR, the above transformers are sized for all load conditions on buses 1NNS-SWG1A and 1NNS-SWG1B.
The 4.16 kV swing bus 1NNS-SWG1C is connected to primary normal bus 1NNS-SWG1B via normally closed circuit breakers and to 1 NNS-SWG1A via normally open circuit breakers.
There are three standby 4.16 kV buses: 1 ENS-SWG1A, 1 ENS-SWG'I B, and 1 E22-S004.
Buses 1ENS-SWG1A and 1ENS-SWG1B are energized from the preferred station service transformers 1RTX-XSR1C and 1RTX-XSR1D, respectively. Standby 4.16 kV bus 1E22-S004 is energized from the normal 4.16 kV swing bus 1 NNS-SWG 1 C.
- 7 Each of these standby 4.16 kV buses has a standby 4.16 kV diesel generator capable of supporting its respective design load upon loss of preferred power. The 4.16 kV standby bus 1 E22-S004 is supported by the high-pressure core spray (HPCS) system diesel generator 1E22-S001G1C.
The design configuration addressed by the licensee's proposed change is the transfer from an onsite power source (main generator output of 22 kV) to an offsite power source. The intent is that the automatic transfer will ensure that adequate power is available from an offsite source to supply the required loads after a loss of the main generator. In the LAR, the licensee stated that the automatic transfer from STX-XNS 1 C to offsite power was included in the initial design of the plant as described in USAR Sections 8.1 and 8.3. The automatic transfer system consists of two schemes. The first scheme is 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 with no time delay. The second scheme is a "slow" transfer which allows the bus voltage to decay sufficiently prior to the transfer. The 'fast" and "slow" transfer schemes are described in detail in Sections 4.2.1 and 4.2.2 of the licensee's submittal dated December 8, 2011 (respectively). The transfer functions are independent and operate sequentially. 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.
American National Standards Institute (ANSI) C50.41, "Polyphase Induction Motors for Power Generating Stations," provides guidance on performing bus transfers. Section 8.3.1.1.3.3 of the RBS USAR states that if either the Division III Standby Service Water Pump (SWP-P2C) or the High Pressure Core Spray Pump (E22-PC001) is in operation, in accordance with the guidance in ANSI C50.41, the fast transfer sequence is blocked to protect those motors. There are a number of additional blocks on the fast transfer, including:
Unit electrical protection trip (time delay; 0.15 seconds)
Main generator primary electrical protection trip (time delay; 0.15 seconds)
Main generator backup electrical protection trip (time delay; 0.15 seconds)
Preferred station service transformer voltage less than 90 percent (no time delay)
STX-XNS1C ground and phase overcurrent (no time delay)
NNS-SWG1A11 B bus undervoltage (less than 80 percent with a 2-second time delay)
Manual trip of generator supply breakers (no time delay)
These blocks are indications of a loss of the power source regardless of the need to transfer and are not part of the fast transfer scheme. If any of those distribution protection blocks are enabled, the fast transfer is not completed, and the slow transfer function is initiated instead.
- 8 The slow transfer scheme is initiated when a loss of voltage signal (less than 80 percent voltage plus a 2-second time delay) is detected on the NNS-SWG1A and/or NNS-SWG1 B buses but it would not be completed unless the voltage on the bus drops down to below 25 percent of rated voltage on these buses. Other blocks for the slow transfer are: preferred station service transformer voltage less than 90 percent and STX-XNS1C overcurrent and ground trip. These protective blocks ensure that offsite power is available and protect the offsite power by preventing transfer if there is a faulted bus.
If neither a fast nor slow transfer initiates, the respective diesel generator will start and supply the safety-related loads on a loss of bus voltage with no additional time delay.
Based on its review of the LAR and supplemental information, the NRC staff identified that breaker E22-S004-ACB4 will only trip after three seconds of a loss of voltage detection on safety-related bus E22-S004. The NRC staff verified that the initiation of the slow transfer will occur prior to initiation of loss of voltage sequence on the Division III bus with a margin of 30 cycles. This ensures that the E22-S004-ACB4 breaker would not trip during a transfer sequence. Therefore, the transfer function would not inhibit the initiation and powering of the E22-S004 bus with the associated diesel generator, as assumed in the accident analysis.
In a request for additional information (RAI) dated May 21, 2012 (ADAMS Accession No. ML12142A048), the NRC staff requested that the licensee explain how it has resolved the NRC staff's concerns identified on page 8-5 of NUREG-0989, "Safety Evaluation Report related to the operation of River Bend Station," May 1984 (not publicly available), related to the potential interaction between the automatic transfer schemes at the 4160 V non-safety-related buses and the automatic starting logic of the diesel generators on the safety-related buses.
By letter dated July 20,2012, in response to the NRC staff's RAI, the licensee stated that RBS had provided an analysis of the diesel starting logic and normal bus transfer logic to the NRC by letter dated February 10,1984 (ADAMS Legacy Accession No. 8402210104). The results of this analysis indicated that there would be no detrimental interaction between the diesel generator starting logic and normal bus transfer logic. This resolved the NRC staff's concerns regarding the interaction between the bus transfer logic and diesel starting logic for the Division I and II buses, as stated in Section 8.3.1 of NUREG-0989. Additionally, the licensee changed a USAR statement that originally indicated that there was an automatic slow transfer at the non-safety-related bus that feeds the Division III (HPCS) bus. This resolved the NRC staffs concerns about the Division III bus. The NRC staff verified that Section 8.3 of the RBS USAR currently states that only manual transfer capability is provided at this bus.
In the LAR, the licensee stated that the transfer function will not affect the availability or operation of the emergency diesel generators.
In its RAI dated May 21,2012, the NRC staff asked the licensee how 1NNS-SWG1A and
'I NNS-SWG1 B would be prevented from cross connecting to each other during an automatic transfer. In its RAI response dated July 20, 2012, the licensee stated that only one bus is procedurally allowed to be connected to NNS-SWG1C during MODES 1,2, and 3. Cross connecting 1 NNS-SWG1A and 'I NNS-SWG1 B is only allowed in MODES 4 and 5 when HPCS is not required to be OPERABLE. Furthermore, the breakers necessary for cross-connection
- 9 are not associated with the automatic transfer scheme. Based on the licensee's response, the NRC staff determined that RBS's procedures and configuration would prevent 1 NNS-SWG1A and 1 NNS-SWG1 B from cross connecting to each other when a fast or slow automatic transfer of bus 1 NNS-SWG 1 C occurs.
In its RAI dated May 21,2012, the NRC staff requested that the licensee provide a discussion of the effects of supplying power to non-safety-related bus 1 NNS-SWG 1 C from the 1 STX-XNS 1 C transformer under both normal and emergent conditions and the available capacity for this new configuration. The licensee provided information in Table 1 of its letter dated July 20,2012, that shows that transformer STX-XNS1 C has adequate capacity to handle the loading under the most limiting condition in all modes during normal and emergency operations.
The NRC staff also requested that the licensee provide a detailed discussion to explain how it had analyzed and resolved the potential issues described in the August 1, 1990, NRC Inspection Report 50-458/40-200, related to the postulated failures of the HPCS pump motors and standby service water 3 pump motors that could result from high transient currents generated during the fast transfer of the Division III bus to offsite power. In its July 20,2012, response, the licensee stated that during a fast transfer from transformer STX-XNS 1 C to transformer RTX-XSR 1 C and/or transformer RTX-XSR1 D the resultant Volts/Hertz for HPCS and standby service water Pump C motors is above the ANSI recommended value of 1.33 as analyzed within calculation G13.18.3.6*010, "Transient Analysis of Fast Transfer of Standby and Normal System from Normal to Preferred Supply." Therefore, a fast transfer block exists when either of the HPCS or standby service water Pump SWP-P2C pump breakers is closed. This block protects these two high critical safety-related motors against damage during the transfer scheme. Based on this information, the NRC staff concludes that a transfer will not damage the motors as it is within the three-second time delay of the loss of voltage signal for bus E22-S004.
Based on its review of the LAR and the additional information provided by the licensee, the NRC staff concludes that there is reasonable assurance that the design of the transfer function scheme at RBS will not adversely impact the capability of the emergency power systems from performing their intended safety functions and, therefore, is acceptable.
Changes to the RBS Technical Specifications The proposed changes would add a requirement to test the automatic transfer function for station service transformer STX-XNS 1 C when powered from the station 22 kV bus. As detailed in Sections 3.1.1 and 3.1.2 of this safety evaluation, the changes include adding a note to LCO 3.8.1, new Required Action A.2, a new Condition B and Required Action B.1, an additional requirement for SR 3.8.1.8, and adding a note to SR 3.8.1.8.
The proposed note to LCO 3.8.1 would explain the TS operability requirements for the automatic transfer function. The NRC staff determined that the new note would ensure that the Division III safety-related bus E22-S004 can be transferred automatically from the 22 kV onsite circuit to the preferred offsite circuit following a plant trip. This supports minimizing the probability of losing electric power from the remaining electric power supplies as a result of a loss of power from the nuclear unit, in accordance with GDC 17.
- 10 The new Required Actions to be added would be identified as A.2 and B.1. Required Action A.2 would be added to ensure that the Division III safety-related bus is aligned to transfer to the transformer powered by the operable offsite circuit when one offsite circuit is inoperable. The NRC staff determined that Required Action A.2 would ensure that Division III safety-related bus E22-S004 is aligned to transfer to the energized preferred station transformer when the other offsite circuit is inoperable. The NRC staff also concludes that the associated Completion Time is reasonable and acceptable given the design configuration.
Required Action B.1 would be added to restore Division III power to the preferred station service transformers when the automatic transfer function is not OPERABLE. The NRC staff determined that Required Action B.1 would address a condition in which a loss of the automatic transfer function capability is found. The NRC staff concludes that the Completion Time is acceptable as it is conservatively bounded by the allowed outage times of the equipment supported by Division III.
The remaining current LCO 3.8.1 Conditions B through G and Required Actions B.1 through G.1 would be renumbered as Conditions C through H and Required Actions C.1 through H.1. In addition, as a result of renumbering the Conditions, the corresponding references in the Completion Times also needed to be renumbered. The NRC staff has reviewed these TS changes and has concluded they are editorial in nature and are, therefore, acceptable.
A new requirement and note would be added to SR 3.8.1.8. This new requirement would require the licensee to test the automatic transfer function every 24 months. Since the automatic transfer does not perform a safety function when the 230 kV offsite circuit is supplying buses NNS-SWG1A or NNS-SWG1B through RTS-XNS1C or RTS-XNS1D, the NRC staff concludes the new note is acceptable.
If the 22 kV onsite circuit is supplying Division III, the automatic transfer of bus E22-S004 through NNS-SWG1A or NNS-SWG1 B from the 22 kV onsite circuit to an offsite circuit is relied on to operate following a trip of the main generator in order to power safety related loads.
Verification of this function is needed to confirm operability. The NRC staff concludes that the proposed surveillances would provide reasonable assurance of the capability to transfer power from the normal offsite circuit to the required alternate offsite circuit and to automatically transfer bus E22-S004 through NNS-SWG1A or NNS-SWG1 B from the 22 kV on site circuit to required offsite circuit.
Based on the above, the NRC staff concludes that the proposed changes to the RBS TS 3.8.1 provides reasonable assurance of the continued availability of the required electrical power to shut down the reactor and to maintain the reactor in a safe condition after an anticipated operational occurrence or a postulated design-basis accident. Furthermore, the NRC staff concludes that the proposed TS changes are in accordance with 10 CFR 50.36(c), and meet the intent of GDCs 17 and 18. Therefore, the NRC staff concludes the proposed TS changes are acceptable.
- 11 4.0 CHANGES TO TS BASES AND REGULATORY COMMITMENTS In Attachment'" and IV to the LAR, the licensee identified (1) changes to the TS Bases for the proposed amendment and (2) the list of regulatory commitments. In identifying changes to the TS Bases, the licensee is not requesting that the NRC approve these changes; the changes to the TS Bases and the regulatory commitment are for the entirety of the proposed LAR dated December 8,2011. The identified changes to the TS Bases come under TS 5.5.11, "Technical Specifications (TS) Bases Control Program," which states, in part, that Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:
- 1.
A change in the TS incorporated in the license; or
- 2.
A change to the USAR that involves an unreviewed safety question as defined in 10 CFR 50.59.
In the LAR, the licensee provided the following regulatory commitments:
- 1)
This section will require revision to include testing of the 4.16 KV normal power supply transfer to preferred power supply.
- 2)
The changes to the affected TS Bases pages will be incorporated in accordance with the TS Bases Control Program.
- 3)
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-XNS 1 C.
- 4)
The revised surveillance will be completed and the transfer function will be verified to be operable prior to alignment through transformer STX-XNS 1 C. This revised surveillance will include both transfer functions.
- 5)
The components used in the transfer function will be added to the maintenance rule monitoring scope.
The licensee committed to complete Commitment 4 on a continuous basis at the first alignment of Division III to STX-XNS1 C. Commitments 1, 2, 3, and 5 will be completed as a one-time action upon the implementation of the amendment. The NRC concludes that these commitments are acceptable.
5.0 STATE CONSULTATION
In accordance with the Commission's regulations, the Louisiana State official was notified of the proposed issuance of the amendment. The State official had no comments.
- 12
6.0 ENVIRONMENTAL CONSIDERATION
The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration, and there has been no public comment on such finding published in the Federal Register on May 1,2012 (77 FR 25757). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.
7.0 CONCLUSION
The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that 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 to the health and safety of the public.
Principal Contributors: M. McConnell A. Matos-Marin Date: December 5,2012
urkhardt JAndersen*
15/12 10/1/12 N RR/DORLlLPL4/BC NRRlDORLlLPL4/PM December 5,2012 Vice President, Operations Entergy Operations, Inc.
River Bend Station 5485 US Highway 61 N St. Francisville, LA 70775
SUBJECT:
RIVER BEND STATION, UNIT 1 -ISSUANCE OF AMENDMENT RE:
PROPOSED CHANGES TO TECHNICAL SPECIFICATION 3.8.1; "AC SOURCES - OPERATING" (TAC NO. ME7695)
Dear Sir or Madam:
The Commission has issued the enclosed Amendment No. 176 to Facility Operating License No. NPF-47 for the River Bend Station, Unit 1 (RBS). The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated December 8,2011, as supplemented by letters dated July 20 and October 26, 2012.
The amendment revises TS 3.8.1, nAC [Alternating Current] - Sources Operating," to include provisions for testing of the automatic transfer function from the onsite 22 kiloVolt bus to offsite power for Division III and the associated standby service water pump powered by the Division III bus. In Section 4.7, "Risk Impact," of the licensee's December 8,2011, submittal, the licensee provided probabilistic insights in support of the amendment request This is not a risk-informed request and, therefore, the NRC staff did not use this risk impact information in its review and approval of this amendment.
A copy of our related Safety Evaluation is enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.
Sincerely, IRAI Alan 8. Wang, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-458
Enclosures:
- 1. Amendment No. 176 to NPF-47
- 2. Safety Evaluation cc w/encls: Distribution via Listserv DISTRIBUTION:
PUBLIC RidsNrrDorlLpl4 Resource RidsRgn4MailCenler Resource LPLIV r/f RidsNrrDssSIsb Resource MMcConneli, NRRlDEIEEEB RidsAcrsAcnw _ MailCTR Resou rce RidsNrrLA.IBurkhardl Resource AMalos-Marin, NRR/DElEEEB RidsNrrDeEeeb Resource RidsNrrPMRiverBend Resource RidsNrrDorlDpr Resource RidsOgcRp Resource ADAMS Accession No. ML12277A308 ~_~____~~~~_*.;;.S,;;.E.;,;m.;.;;e.;.;,m;,;;.o..;;d;,,;;,at;.;;.ed;;;;.-
OFFICE NRRlDORLlLPL4/PM RR/DORLlLPL4/LA NRR/DE/EEEB/BC NRR
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NAME ABWang DATE 11/27/12 OFFICE OGC - NLO
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MMarkley ang NAME 12/4/12 12/5/12 DATE OFFICIAL AGENCY RECORD