ML051860407
| ML051860407 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 07/01/2005 |
| From: | Bo Pham NRC/NRR/DLPM/LPD4 |
| To: | Ray H Southern California Edison Co |
| pham b m, nrr dlpm lpdiv-2, 301-415-8450 | |
| Shared Package | |
| ML051860411 | List: |
| References | |
| TAC MC7190, TAC MC7191 | |
| Download: ML051860407 (24) | |
Text
July 1, 2005 Mr. Harold B. Ray Executive Vice President Southern California Edison Company San Onofre Nuclear Generating Station P.O. Box 128 San Clemente, CA 92674-0128
SUBJECT:
SAN ONOFRE NUCLEAR GENERATING STATION, UNITS 2 AND 3 -
ISSUANCE OF AMENDMENTS ON DEGRADED VOLTAGE SETPOINTS (TAC NOS. MC7190 AND MC7191)
Dear Mr. Ray:
The Commission has issued the enclosed Amendment No. 196 to Facility Operating License No. NPF-10 and Amendment No. 187 to Facility Operating License No. NPF-15 for San Onofre Nuclear Generating Station, Units 2 and 3, respectively. The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated May 27, 2005, as supplemented by letters dated June 7, June 24, and July 1, 2005.
The amendments revise TS 3.3.7, DG-Undervoltage Start," by changing Surveillance Requirement 3.3.7.3.a to lower the allowable values for dropout and pickup of the degraded voltage function.
A copy of our related Safety Evaluation is also enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.
Sincerely,
/RA/
Bo M. Pham, Project Manager, Section 2 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-361 and 50-362
Enclosures:
- 1. Amendment No. 196 to NPF-10
- 2. Amendment No. 187 to NPF-15
- 3. Safety Evaluation cc w/encls:
See next page
July 1, 2005 Mr. Harold B. Ray Executive Vice President Southern California Edison Company San Onofre Nuclear Generating Station P.O. Box 128 San Clemente, CA 92674-0128
SUBJECT:
SAN ONOFRE NUCLEAR GENERATING STATION, UNITS 2 AND 3 -
ISSUANCE OF AMENDMENTS ON DEGRADED VOLTAGE SETPOINTS (TAC NOS. MC7190 AND MC7191)
Dear Mr. Ray:
The Commission has issued the enclosed Amendment No. 196 to Facility Operating License No. NPF-10 and Amendment No. 187 to Facility Operating License No. NPF-15 for San Onofre Nuclear Generating Station, Units 2 and 3, respectively. The amendments consist of changes to the Technical Specifications (TSs) in response to your application dated May 27, 2005, as supplemented by letters dated June 7, June 24, and July 1, 2005.
The amendments revise TS 3.3.7, DG-Undervoltage Start," by changing Surveillance Requirement 3.3.7.3.a to lower the allowable values for dropout and pickup of the degraded voltage function.
A copy of our related Safety Evaluation is also enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.
Sincerely,
/RA/
Bo M. Pham, Project Manager, Section 2 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-361 and 50-362
Enclosures:
- 1. Amendment No. 196 to NPF-10
- 2. Amendment No. 187 to NPF-15
- 3. Safety Evaluation cc w/encls:
See next page DISTRIBUTION PUBLIC PDIV-2 r/f GHill (4)
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TS: ML051870239/ML051870238 NRR-100 PKG: ML051860411 ACCESSION NO: ML051860407 NRR-058 OFFICE PDIV-2/PM PDIV-1/LA IROB/SC EEIB-A/SC EEIB-B/SC OGC PDIV-2/SC NAME BPham DBaxley TJader for TBoyce AHowe RJenkins AFernandez MFields for DCollins DATE 7/1/05 7/1/05 7/1/05 6/30/05 7/1/05 7/1/05 7-1-05 OFFICIAL RECORD COPY DOCUMENT NAME: E:\\Filenet\\ML051860407.wpd
SOUTHERN CALIFORNIA EDISON COMPANY SAN DIEGO GAS AND ELECTRIC COMPANY THE CITY OF RIVERSIDE, CALIFORNIA THE CITY OF ANAHEIM, CALIFORNIA DOCKET NO. 50-361 SAN ONOFRE NUCLEAR GENERATING STATION, UNIT 2 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 196 License No. NPF-10 1.
The Nuclear Regulatory Commission (the Commission) has found that:
A.
The application for amendment by Southern California Edison Company, et al.
(SCE or the licensee), dated May 27, 2005, as supplemented by letters dated June 7, June 24, and July 1, 2005, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations set forth in 10 CFR Chapter I; B.
The facility will operate in conformity with the application, 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 (ii) that such activities will be conducted in compliance with the Commission's regulations; D.
The issuance of this 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.
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-10 is hereby amended to read as follows:
(2)
Technical Specifications The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 196, are hereby incorporated in the license. Southern California Edison Company shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
3.
This license amendment is effective as of the date of its issuance and shall be implemented within 30 days of issuance.
FOR THE NUCLEAR REGULATORY COMMISSION
/RA by Mel B. Fields for/
Daniel Collins, Acting Chief, Section 2 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation
Attachment:
Changes to the Technical Specifications Date of Issuance: July 1, 2005
ATTACHMENT TO LICENSE AMENDMENT NO. 196 FACILITY OPERATING LICENSE NO. NPF-10 DOCKET NO. 50-361 Replace the following page of the Appendix A Technical Specifications with the attached revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.
REMOVE INSERT 3.3-34 3.3-34
SOUTHERN CALIFORNIA EDISON COMPANY SAN DIEGO GAS AND ELECTRIC COMPANY THE CITY OF RIVERSIDE, CALIFORNIA THE CITY OF ANAHEIM, CALIFORNIA DOCKET NO. 50-362 SAN ONOFRE NUCLEAR GENERATING STATION, UNIT 3 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 187 License No. NPF-15 1.
The Nuclear Regulatory Commission (the Commission) has found that:
A.
The application for amendment by Southern California Edison Company, et al.
(SCE or the licensee), dated May 27, 2005, as supplemented by letters dated June 7, June 24, and July 1, 2005, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations set forth in 10 CFR Chapter I; B.
The facility will operate in conformity with the application, 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 (ii) that such activities will be conducted in compliance with the Commission's regulations; D.
The issuance of this 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.
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-15 is hereby amended to read as follows:
(2)
Technical Specifications The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 187, are hereby incorporated in the license. Southern California Edison Company shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.
3.
This license amendment is effective as of the date of its issuance and shall be implemented within 30 days of issuance.
FOR THE NUCLEAR REGULATORY COMMISSION
/RA by Mel B. Fields for/
Daniel Collins, Acting Chief, Section 2 Project Directorate IV Division of Licensing Project Management Office of Nuclear Reactor Regulation
Attachment:
Changes to the Technical Specifications Date of Issuance: July 1, 2005
ATTACHMENT TO LICENSE AMENDMENT NO. 187 FACILITY OPERATING LICENSE NO. NPF-15 DOCKET NO. 50-362 Replace the following page of the Appendix A Technical Specifications with the attached revised page. The revised page is identified by amendment number and contains marginal lines indicating the areas of change.
REMOVE INSERT 3.3-34 3.3-34
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 196 TO FACILITY OPERATING LICENSE NO. NPF-10 AND AMENDMENT NO. 187 TO FACILITY OPERATING LICENSE NO. NPF-15 SOUTHERN CALIFORNIA EDISON COMPANY SAN DIEGO GAS AND ELECTRIC COMPANY THE CITY OF RIVERSIDE, CALIFORNIA THE CITY OF ANAHEIM, CALIFORNIA SAN ONOFRE NUCLEAR GENERATING STATION, UNITS 2 AND 3 DOCKET NOS. 50-361 AND 50-362
1.0 INTRODUCTION
By application to the Nuclear Regulatory Commission (NRC) dated May 27, 2005 (Agencywide Documents and Access Management System (ADAMS) Accession No. ML051530034),
Southern California Edison Company (SCE or the licensee), requested a change to the operating license for the San Onofre Nuclear Generating Station (SONGS), Units 2 and 3. The supplements dated June 7, June 24 (ADAMS Accession Nos. ML051610228 and ML051790269), and July 1, 2005, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the staff's original proposed no significant hazards consideration determination as published in the Federal Register on June 14, 2005 (70 FR 34506).
The proposed amendments revise Technical Specification (TS) 3.3.7, DG [diesel generator]-
Undervoltage Start," by changing Surveillance Requirement (SR) 3.3.7.3.a to lower the allowable values for dropout and pickup of the degraded voltage function.
Currently, the SONGS, Units 2 and 3 switchyard minimum voltage that supports plant safety equipment operability is 218 kV for the normal preferred power source. A written agreement is in effect which requires the California Independent System Operators (the Grid Operator) to manage grid operations to ensure that the SONGS switchyard voltage will remain above this minimum voltage under the most limiting condition. The most limiting condition for offsite grid voltage involves one SONGS unit shutdown and a trip of the remaining unit. The Grid Operator is required to notify SCE if grid operating conditions can not satisfy the above criterion. SCE would then declare offsite power inoperable and would enter the appropriate TS Action. SCE has recently performed evaluations that indicate that below an offsite grid voltage of 222.2 kV, the 4.16 kV Class 1E bus voltages might not be able to recover above the upper reset limit of the degraded voltage protection circuits. In the case of one unit shutdown and a trip of the remaining unit, the post-trip voltage could be between 218 kV and 222.2 kV. In this case the degraded voltage protection relays could cause SONGS, Units 2 and 3, to separate from the immediate access offsite power source even though offsite power would still be available at acceptable voltage levels.
During a teleconference call and public meeting on June 3 and June 10, 2005, respectively, the NRC staff requested that the licensee provide additional information in order to complete its review. By letters dated June 7, June 24, and July 1, 2005, the licensee provided the requested information.
2.0 BACKGROUND
2.1 General To provide a reliable source of power for the engineered safety features (ESF) systems, nuclear power plants are provided with redundant offsite (preferred), and onsite (standby) power sources, such as the DGs. The power sources for the ESF systems are classified as Class 1E safety-related power sources. The DGs provide an alternate source of power to the ESF systems if the preferred power source is lost (i.e., loss of voltage (LOV) condition) or is in degraded grid voltage (DGV) condition. Each Class 1E bus is equipped with undervoltage (UV) relays comprising of LOV and DGV relays to permit automatic transfer to the alternate preferred power source and for starting of DGs.
2.2 SONGS Design At SONGS, two 4.16 kV Class IE buses per unit provide offsite power sources for the ESF systems. UV relay protection for the SONGS, Units 2 and 3, Class 4.16 kV buses is described in the Updated Final Safety Analysis Report (UFSAR) Section 8.3.1.1.3.13.B, "Electrical Circuit Protection Systems." As described in the UFSAR, each of these 4.16 kV Class IE buses per unit is equipped with UV relays and timing relays to permit automatic transfer to the alternate preferred power source and for starting of DGs. The UV relaying scheme is designed to perform the following:
2.2.1 LOV Protection Four UV relays (Westinghouse CV-2 induction disk relays with inverse time characteristics) 127F1, F2, F3, and F4 are provided on each 4.16 kV Class 1E bus. The output contacts of the relays are combined in a two-out-of-four logic to generate an LOV signal with a time delay of approximately 1 second for complete LOV. An LOV signal with safety injection actuation signal (SIAS) will transfer the 4.16 kV Class 1E bus to the the DG. An LOV signal without SIAS will transfer the 4.16 kV Class 1E bus to the alternate preferred power source and if the alternate power source is not available it will transfer the 4.16 kV Class 1E bus to the DG.
2.2.2 DGV Protection Four UV relays (ASEA Brown Boveri ABB 27N, definite time delay solid state relays), 127D1, 2, 3, and 4, along with four timing relays, 162D1, 2, 3, and 4, are provided on each 4.16 kV Class 1E bus for the DGV detection scheme.
The voltage and time delay settings are such that permanently connected Class 1E loads will not be damaged due to a degraded voltage condition. The existing 127D relays are set to operate at 4228 V, with a response time of 2 seconds. The 162D relays are set at 110 seconds. As such, a sustained degraded voltage (SDV) signal will be generated within approximately 112 seconds. This signal will be blocked when the 4.16 kV Class 1E bus is powered from the DG. These signals are combined in a two-out-of-four logic and the resulting signal is referred to as the sustained degraded voltage signal (SDVS). An SDVS with SIAS will transfer the 4.16 kV Class 1E bus to the DG. An SDVS without SIAS will transfer the 4.16 kV Class 1E bus to the alternate preferred source and if the alternate preferred power source is not available, SDVS without SIAS will transfer the 4.16 kV Class 1E bus to the DG. The voltage and time delay settings for these relays are such that permanently connected Class 1E loads will be maintained within equipment operating voltage ranges.
2.2.3 DGV with SIAS Signal (DGVSS)
One output contact from each of the 127D1, 2, 3, and 4 relays is used in a SDV protection scheme along with a set of timing relays for DGV protection concurrent with a SIAS.
The voltage and time delay settings are such that signals will be generated with an intentional definite time delay upon initiation of a SIAS along with the degraded bus voltage as sensed by the 127D1, 2, 3, and 4 relays during the first load sequence cycle only. This scheme is designed to actuate in the event of a SIAS with a degraded grid condition. These signals are combined in a two-out-of-four logic and the resulting signal is referred to as DGVSS.
The 4.16 kV Class 1E buses are transferred directly to the DG rather than to the alternate preferred power source, which is likely to be experiencing a degraded voltage condition as well.
The time delay for this signal is chosen to ride through the voltage transients and to ensure that adequate voltage is available on the 4.16 kV Class 1E bus during post accident ESF load sequencing. This time delay is initiated by SIAS, and is independent of the time delay chosen for SDVS. Following the acceleration of the first load group during post accident ESF load sequencing, the degraded voltage scheme will have a brief duration in which to sense the voltage on the 4.16 kV Class 1E bus. If the voltage is below the minimum analyzed value, the 4.16 kV Class 1E bus will separate from the preferred power source and transfer to the DG.
The SONGS TSs include requirements for periodic surveillance of the UV relays to provide assurance that they would function during potential LOV and DGV conditions. These surveillances measure the dropout voltage at which the relay actuates upon sensing degraded bus voltage, and also the pickup voltage at which the relay resets to enable sequencing of ESF loads onto the bus. The SRs in the SONGS TSs ensure operability of the relays to protect the ESF loads against degraded voltage, and to ensure that appropriate ESF equipment is loaded to the power source in the proper sequence such that the bus is not overloaded.
3.0 REGULATORY EVALUATION
The NRC staff applied the following regulatory requirements in its review of the licensees application:
Part 50 of Title 10 of the Code of Federal Regulations (10 CFR) Appendix A, General Design Criterion (GDC) 17, "Electric power systems," requires that 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 shall be to provide sufficient 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 (AOOs) and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents. The DGV and LOV relay trip set points and associated time delays assure proper operation of safety-related loads as required by GDC 17 of 10 CFR Part 50, Appendix A.
An actuation signal from the UV relays, trips the offsite power supply breaker to the load group. Tripping the supply breaker isolates (and thus protects) the load group from the degraded and transient voltage conditions that may exist on the offsite power supply.
This protection, pursuant to the requirements of GDC 17, minimizes 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. This protection thus supports the availability of power to the load group when needed (assuming the offsite system is not functioning) to assure fuel design limits and design conditions of the reactor coolant boundary are not exceeded as a result of AOOs and to assure the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents.
The proposed change lowers the allowable values for the degraded voltage protection relays. The proposed allowable values will ensure SONGS, Units 2 and 3, will not separate at or above 218 kV. This minimizes the probability of losing electric power from the immediate access offsite power source as the result of a unit trip while the other unit is shutdown.
GDC 18, Inspection and testing of electric power systems, of Appendix A of 10 CFR Part 50, requires that electric power systems that are important to safety must be designed to permit appropriate periodic inspection and testing.
10 CFR 50.36, "Technical specifications," requires a licensees TS to establish Limiting Conditions for Operation and SRs for equipment that is required for safe operation of the facility. Specifically, Section 50.36(c)(1) which stipulates the items to be included in the TS and Section 50.36(c)(3) which stipulates the SRs.
The NRC staff also referenced GDC 20, "Protection system functions," and GDC 21, "Protection system independence," of Appendix A of 10 CFR Part 50. In addition, the NRC staff referred to the following documents during its evaluation of the proposed TS changes:
a.
Regulatory Guide (RG) 1.105, Revision 3, "Setpoints for Safety-Related Instrumentation," dated December 1999. This RG describes the method acceptable to the NRC staff for complying with the regulations for ensuring that setpoints for safety-related instruments are initially within and remain within the TS limits.
b.
Part I of Instrumentation, Systems, and Automation Society (ISA) Standard, ISA-S67.04-1994, "Setpoints for Nuclear Safety-Related Instrumentation,"
subject to NRC staff clarifications and Part II of ISA-S67.04-1994, "Methodologies for determination of Setpoints for the Nuclear Safety-Related Instrumentation." The RG 1.105 endorses Part I of ISA-S67.04-1994.
- c.
SONGS Licensee Event Report No. 2005-003, dated May 11, 2005, which documents the licensees discovery of the potential for early separation from the preferred offsite power source.
d.
The UFSAR for SONGS, Units 2 and 3, specifically USFAR Section 8.3.1.1.3.13.B.
4.0 TECHNICAL EVALUATION
The proposed TS changes are as follows:
Currently, SR 3.3.7.3 requires performance of channel calibration for degraded voltage function with setpoint as follows: The dropout voltage allowable value is $4196 V and that pickup voltage allowable value is #4281 V. The proposed change will revise these allowable values to
$4123.0 V and #4144.6 V for dropout and pickup, respectively.
In addition, a footnote will be added to these allowable values which will state, Dropout and pickup values will be set to $4151.0 V and #4172.8 V, respectively, until actions identified in SCE submittal dated May 27, 2005, are completed.
Permanent Change Based on Minimum Switchyard Voltage of 218 KV The licensee stated that the proposed dropout allowable value of $4123.0 V is based on the analysis limit of 4106 V and calculated as follows: dropout allowable value is $lower analysis limit (4106 V) + total loop uncertainties (16.5 V)+ margin (6 V) - allowable value tolerance (5.5 V) or (4106+16.5+6-5.5) or 4123.0 V. The pickup allowable value is # nominal dropout value (lower analysis limit+total loop uncertainties+ margin) + relay deadband (10.6 V) +
allowable value tolerance or (4106+16.5+6 +10.6+5.5) or 4144.6 V.
The licensee stated that the proposed degraded voltage relay dropout setpoint is based on voltage response analyses. It was selected to ensure all safety-related loads have sufficient voltage to perform their intended safety function. Therefore, the minimum dropout voltage of the proposed degraded voltage protection relay must be greater than the lower analysis limit voltage. The criteria used to determine the setpoint included:
C Providing degraded voltage setpoints that support the voltage requirements of the Class 1E loads at all onsite system distribution levels (i.e., 4.16 kV, 480 V, and 120/208V).
C Providing minimum continuous running voltage (nominally 90 percent of nameplate voltage) to Class 1E motors on the emergency buses.
C Providing adequate motor terminal voltage during starting and accelerating period such that the corresponding motor torque is constantly more than the load required allowing the motor to accelerate to its rated speed.
The lower analysis limit, that is, the voltage at which all safety-related loads have sufficient voltage to perform their intended safety function (provided the modifications identified in this amendment request are completed) was determined to be 4106 V. This was based on minimum switchyard voltage of 215.234 kV. The licensee has stated that it will notify the NRC staff once the modifications are completed. In addition, during a telephone conversation with the NRC staff on June 30, 2005, Mr. Jack Rainsberry of SCE informed the NRC that SCE expects to complete the modification no later than July 3, 2005.
The proposed degraded voltage relay pickup setpoint is determined by adding the relay deadband (0.3 V at 120 V level) to the dropout setpoint. It was selected to ensure that the 4.16 kV bus remains connected to the normal preferred offsite power source when the switchyard voltage is 218 kV and above. The following criteria are used:
C The maximum pickup voltage of the degraded voltage protection relay should be less than the voltage corresponding to the minimum switchyard voltage of 218 kV.
C The 4.16 kV bus voltage at 4.11 seconds (for grid voltage to recover from a short term voltage transient due to system disturbance or SONGS unit trip) during load sequencing should be greater than the maximum pickup voltage of the degraded voltage protection relay when switchyard voltage is 218 kV.
The upper analysis limit was determined to be 4161 V. The calculated 4.16 kV bus voltage at 4.11 second is 4190.8 V when the switchyard voltage is 218 kV. This is greater than the upper analysis limit of 4161 V. Hence, the 4.16 kV bus will remain connected to the normal preferred (offsite) source during the load sequencing when the unit experiences a design-basis accident (DBA).
The licensee used the Electrical Transient Analyzer Program (ETAP) to perform the power system analysis and the system model is developed from licensee-approved design drawings and procedures. The system model reflects the configuration of SONGS and the expected configurations under DBA conditions. Connected loads and their operating conditions used in the model (i.e., percent loading, duration, etc.) are based on available design information for meeting its most demanding design requirements. The results of the analysis confirm that all essential loads in the system will have adequate voltage to perform its design function as long as the voltages remain at or above the analytical limit of 4106 V or 98.7 percent of 4160 V at the 4.16kV safety-related buses.
The staff evaluated the assumptions, loading, and summary of results provided by the licensee in its supplemental letter dated June 24, 2005, and finds them acceptable. The staff noted that the ETAP is widely accepted and used in the industry as the power system analysis tool. This program meets 10 CFR Part 50, Appendix B requirements and has been verified and validated for use. The system modeled in the ETAP was developed in accordance with licensee-approved design drawings and procedures.
Since it takes approximately 6.6 seconds (4.44 seconds delay + 2.17 seconds relay time) for the degraded grid relays to disconnect from the offsite power source when SIAS signal is present, the staff requested the licensee to describe (1) what happens to those loads that are already sequenced on the safety buses assuming concurrent SIAS and degraded grid, (2) the operation of the loads if SIAS occurs first in the above scenario, and (3) if there would be any problem in re-starting those loads on the DG. In its June 24, 2005, response, the licensee, stated that the time delay relay 162S for DGVSS window opening time is started by SIAS independent of time delay of the degraded grid relay. The DGVSS window opens if 162S relay and associated 127D have operated. The window is closed when time delay 162T operates.
Thus the DGVSS window opens between 4.11 and 4.49 seconds (4.3 +/- 0.19 seconds) and closes between 4.96 and 6.14 seconds from initiation of SIAS. All motor loads that were running and started in Load Group 1 will be tripped if the DGVSS is initiated. Following initiation of a DGVSS, there is an additional time delay of 2.0 +/- 0.20 seconds provided for tripping and decaying of voltage at the loads prior to re-energizing the loads. Following the 2 second time delay, the DG breaker will close, provided the bus voltage has decayed to 25 percent (detected by 127R relays) and the DG has attained normal voltage and speed. Then the loads in Load Group 1 will restart and all other loads will start in proper sequence. The motors are designed for two starts in succession with the motor at ambient temperature or one restart from running temperature condition per Parts 12 and 20 of National Electrical Manufacturers Association MG-1. There will be no anticipated degradation that would prevent the restarting of these loads on the DG. Therefore, the above response by the licensee satisfies the staffs questions.
Since on a sustained degraded grid condition, the SDVS will separate safety buses from the offsite power system if the grid conditions are not improved within 130 seconds, the staff requested the licensee to clarify if the plant will be tripped under these conditions; if it does, what signal trips the reactor in this scenario; if it does not, what actions are taken to prevent sequencing of safe shutdown loads on the safety bus when supplied by DG. The licensee, in its June 24, 2005, response, stated that under a sustained degraded grid condition, the SDVS will separate the buses from the offsite power. There is no signal to automatically trip the plant under this condition. After separation of the safety buses following either a degraded grid condition or a loss-of-offsite power (LOOP) condition, the 4160 V buses are stripped of all motor loads and then connected to the DGs. If there is no accident, there is no automatic sequencing of loads onto the 4160 V and 480 V buses. The safe shutdown loads are permanently connected to the 4160 V and 480 V buses with the exception of the component cooling, salt water cooling, and shutdown cooling (if required) pumps which the operators will manually reconnect onto the buses. In addition, auxiliary feed water pumps will auto connect if emergency feedwater actuation signal is present. In the event of a degraded grid condition, the effects on specific plant loads may cause the operator to manually trip the plant (the licensee has stated that it would revise UFSAR Section 8.3.1.1.4.6 to clarify this point). The above response from the licensee satisfies the staffs questions.
Interim Change Based on Minimum Switchyard Voltage of 219.5 kV The licensee stated that in order to fully implement its proposed change, certain modifications and testing must be completed. All required modifications and testing identified in the amendment request may not be completed by July 1, 2005. Therefore, as part of this proposed change, a footnote is added to the proposed degraded voltage dropout and pickup allowable values that will allow for interim degraded voltage allowable values. All modifications and testing required to implement the proposed interim option are expected to be completed by July 3, 2005. The proposed interim allowable values (4151.0 V for dropout and 4172.8 V for pickup) are between the current and proposed allowable values. This interim option allows SCE to temporarily establish 219.5 kV as the minimum offsite grid voltage necessary to support operability of the immediate access offsite power source until such time as the final proposed degraded voltage allowable values may be implemented. Modifications and testing necessary to implement the final proposed change are expected to be completed within a short time following July 1, 2005. Once all modifications and testing are completed, the proposed interim allowable values will no longer be applicable, and the proposed allowable values of $4123.0 V and #4144.6 V for dropout and pickup, respectively, will be effective from that time forward.
The proposed interim degraded voltage protection scheme is designed to ensure that the 4.16 kV Class 1E buses: (1) do not separate from the normal preferred power source and do not transfer to the DG when the switchyard voltage is at or above 219.5 kV and (2) provide adequate voltage to support operability of plant equipment. The proposed interim allowable values are lower than the existing allowable values and the range between dropout and pickup for the proposed interim allowable values is smaller than the range between dropout and pickup for the existing allowable values. This was accomplished by eliminating unnecessary conservatism in the allowable value setpoint calculations. The calculations showed:
(1)
The lower analysis limit, that is, the voltage at which all safety-related loads have sufficient voltage to perform their intended safety function provided the modifications identified in this amendment request are completed, was determined to be 4139 V. This was based on minimum switchyard voltage of 216.89 kV.
(2)
The upper analysis limit was determined to be 4190 V. The calculated 4.16 kV bus voltage at 4.11 seconds is 4219.5 V when the switchyard voltage is 219.5 kV. This is greater than the upper analysis limit of 4190 V. Hence, the 4.16 kV bus will remain connected to the normal preferred (offsite) source during the load sequencing when the unit experiences a DBA. In its May 27, 2005, submittal, the licensee stated that modifications necessary for the interim change would be completed by July 1, 2005.
During a telephone conversation with the NRC staff on June 30, 2005, however, Mr.
Jack Rainsberry of SCE informed the NRC staff that modification work was underway, and is planned to be completed no later than July 3, 2005.
In addition, on a teleconference with the licensee on July 1, 2005, the NRC staff requested the licensee to address two additional questions:
(1)
The staff noted that in a submittal dated July 20, 2000 (ADAMS Accession No. ML003734882), related to revising the acceptance criteria for TS 3.3.7, the licensee reported that as-found dropout voltages for the 127D relays (that were set at 4228 V) were between 4210.5 V and 4239.9 V. This represents a 17.5 to 11.9 V (or 0.41 percent to 0.28 percent) variation to the setpoint. In the case of the as-found pickup voltages, the subject submittal listed, for the 127D relays, measurements from 4233.25 to 4248.3 V. This represents a 5.25 to 20.3 V (or 0.02 percent to 0.48 percent) variation to the setpoint. Since as-found data represents the actual operating experience that reflect all of the instrument uncertainties, please explain the appropriateness of using the interim dropout setpoint of 4156.5 V given the minimum relay dropout setpoint of 4139.7 V. According to Calculation E4C-90, ICCN C-130 (Attachment N of the licensees submittal dated May 27, 2005), the minimum relay dropout setpoint of 4139.7 V was utilized in the subject calculation to confirm Class 1E equipment operability. Further, given (1) the narrow relay setpoint margins cited above and (2) the nominal relay setpoint surveillance frequency noted by the relay manufacturer is 1 to 2 years, why is one relay setpoint check one month after operation at the new setpoint sufficient to validate Assumptions 3.2.1 (UV Relay Deadband Adjustment) and 3.2.2 (UV Relay Drift) used in Calculation E4C-130, ICCN C-7 (Attachment H of the licensee submittal dated May 27, 2005)?
(2)
In its submittal dated May 27, 2005, the licensee stated that the evaluation of the effect of this proposed change on voltages at the 120 V level is ongoing, and will be completed by July 1, 2005. This evaluation will determine what additional modifications similar to those described in this PCN will be necessary in order to ensure operation with the attached calculations of voltage at the 4160 V level. What additional modifications are necessary, and what is the potential impact on the operability of 120-V equipment due to instrument drift or errors with use of the interim relay setpoint at 4156.5 V (See Question 1)?
In its response by letter dated July 1, 2005, the licensee stated that (1) the final proposed option (218 kV) will be implemented without first implementing the proposed interim setpoint for operation at 219.5 kV and (2) the 120-V evaluation has been completed and it has identified two additional tests that must be completed prior to implementation of the final proposed option (218 kV). This response resolves the staffs concern regarding the implementation of the interim setpoint for operation at 219.5 kV.
Setpoint Calculation Methodology The staff evaluated the changes to the allowable values for pickup and dropout setpoints of the DGV relays during channel calibration to SR 3.3.7.3. The licensee provided Calculation E4C-130, ICCN C-7, in Attachment H, and E4C-130, ICCN C-3, in Attachment L, for calculating the allowable value, nominal setpoint, setpoint as-left acceptance band, setpoint as-found acceptance band, total loop uncertainty, and allowable value tolerance, corresponding to 218 kV and 219.5 kV grid voltages, respectively. These two calculations are based on the licensees current setpoint calculation methodology in SCE Standard JS-123-103C, Revision 4, "Instrument Setpoint/Loop Accuracy Calculation Methodology." The proposed allowable values are lower than existing allowable values in SR 3.3.7.3 and the range between dropout and pickup for the proposed allowable values is smaller than the range between dropout and pickup for the existing allowable values. The licensee stated that it accomplished this by eliminating unnecessary conservatism in the allowable value setpoint calculations.
The licensee stated that the total loop uncertainty and allowable value calculation methodology for the DGV protection circuits is consistent with the Method 3 calculation methodology of ISA-RP67.04.02-2000. The licensee, further, stated that it has performed an evaluation and determined that the proposed degraded voltage allowable values are slightly conservative to values calculated using Method 2. The staff finds that the methodology used to calculate allowable value, total loop uncertainty, allowable value tolerance, as-left acceptance band, and as-found acceptance band for SDVS to be consistent with Method 3 of Part II of ISA-S67.04-1994. Starting with a lower analysis limit of 4106 V, in calculation E4C-130, ICCN C-7, the licensee used a margin of 6 V (0.146 percent) and added total loop uncertainty of 16.5 V (0.4 percent) in calculating the nominal setpoint of 4128.5 V (4106 + 16.5 + 6 =
4128.5 V) for SDVS UV relay dropout for lower analysis limit of 4106 V. The licensee calculated the nominal setpoint of 4139.1 V (4128.5 + 10.6 = 4139.1) for SDVS UV relay pickup by adding a deadband of 10.6 V, resulting in a margin of 5.4 V for upper analysis limit of 4161.0 V. From the pickup and dropout nominal setpoints, the licensee used an allowable value tolerance of 5.5 V to arrive at the upper bound of the as-found band for pickup to be
- 4144.6 V (TS allowable value) and the lower bound of the as-found dropout to be $ 4123.0 V (TS allowable value). Thus, the margins of 5.4 V and 6 V essentially compensate for the allowable value tolerance of 5.5 V. Because of this high margin, the staff concludes that the proposed DGV allowable values are acceptable.
The licensee assumed a drift of +0.1 percent for calculating as-left acceptance band for pickup and dropout setpoints. Compared to this as-left acceptance band, the licensee calculated a tolerance +0.4 percent for total loop uncertainty, a tolerance of +0.132 percent for allowable value tolerance, a margin of +0.131 percent for pickup and a margin of 0.146 percent for dropout. The staff concludes that the margins used in the setpoint calculations provide good compensation in the event the assumed drift of +0.1 percent proves to be too low in field verification later. The licensee stated that one month after operation at the new setpoints it will collect and forward to engineering for analysis the as-found data on SDVS UV relay dropout and pickup to verify the Assumptions 3.2.1 and 3.2.2 of the Calculations E4C-130, ICCN C-7, E4C-130, and ICCN C-3. In these calculations, an UV relay deadband (the difference between the UV relay pickup and dropout) of 0.3 V has been assumed for Assumption 3.2.1 (for calculating pickup setpoint from dropout setpoint), based on the manufacturer specified data, and UV relay drift allowance +/- 0.1 percent has been assumed for Assumption 3.2.2. In addition, the licensee stated that if any allowable values are exceeded during this interval, then engineering will evaluate the assumption and calibration methodology.
The licensee stated that it is aware of the ongoing generic issues with setpoint calculation methodology, particularly as described in the NRCs letter dated March 31, 2005, (ADAMS Accession No. ML050870008) from James A. Lyons of NRC to Alex Marion of Nuclear Energy Institute (NEI). The March 31, 2005, letter relates NRCs concern about the methods of Part II of ISA-S67.04-1994 for determining trip setpoints and allowable values.
The licensee stated in Enclosure 2 of its May 27, 2005, license amendment request that when performing instrument setpoint calibrations, the as-left values are always left or adjusted to within the established setting tolerance band for the setpoint calibrations of the SDVS in accordance with existing SONGS plant procedures. The SONGS TS Bases for SR 3.3.7.3, Channel Calibration, states that "The channel shall be left calibrated consistent with the assumptions of the current plant specific setpoint analysis."
In addition, the licensee stated in Enclosure 2 of its amendment request that it is a participant in the NEI Setpoint Methodology Task Force that is currently drafting a TS Task Force (TSTF) traveler to standardize how utilities determine trip setpoints and allowable values for limiting safety system setting. As mentioned in the March 31, 2005, letter, this effort may result in the NRCs approval of a Consolidated Line Item Improvement Process (CLIIP) on this subject. In its May 27, 2005, submittal, the licensee committed to evaluate the industry solution contained in the CLIIP and implement it as appropriate.
5.0 EXIGENT CIRCUMSTANCES
The licensees amendment request was submitted on an exigent basis because this change will reduce the potential for an unnecessary dual-unit shutdown during high summer load periods.
Currently, the SONGS, Units 2 and 3, switchyard minimum voltage immediate access offsite power source operability is 218 kV. SCE has, however, performed recent evaluations that indicate 222.2 kV is the actual voltage required for operability of the immediate access offsite power source. SCE has therefore, shifted to utilizing 222.2 kV as the minimum voltage necessary to support operability of the immediate access offsite power source. The plants limiting condition would be when one unit is shut down and a subsequent trip occurs at the remaining unit. If post trip voltages are between 218 kV and 222.2 kV, the degraded voltage relays could cause SONGS to separate from the immediate access offsite power source prematurely, thus protecting the safety functions via the DGs, but not remaining on the preferred offsite source. As a result, should one unit at SONGS shut down during a high summer load period, grid conditions (voltages below 222.2 kV) could force the unnecessary shutdown of the remaining unit. The licensee requests approval of the proposed amendment by July 1, 2005, to support re-establishing 218 kV as the minimum switchyard voltage to avoid the limiting condition during the grids peak load season. Therefore, the licensee requests that this proposed license amendment be considered under exigent circumstances as described in 10 CFR 50.91(a)(6).
Based on the above circumstances, the NRC finds that the licensee used its best efforts to make a timely application as soon as it discovered the limiting scenario for entering a high summer load period, and could not have avoided the need for the exigency. The NRC also finds that, in light of these circumstances, the licensee and the Commission must act quickly and time does not permit the Commission to publish a Federal Register notice allowing 30 days for prior public comment. As set forth below, the NRC has determined that this amendment involves no significant hazards consideration. Based on the foregoing, the NRC finds that exigent circumstances exist as defined in 10 CFR 50.91(a)(6), with regard to the license amendment requested by the licensee's application dated May 27, 2005.
6.0 FINAL NO SIGNIFICANT HAZARDS CONSIDERATION
DETERMINATION The Commissions regulations in 10 CFR 50.92 state that the Commission may make a final determination that a license amendment involves no significant hazards considerations if operation of the facility in accordance with the amendment would not: (1) involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) involve a significant reduction in the margin of safety. Based on its analysis, the NRC staff has concluded that:
- 1. The proposed change will not involve a significant increase in the probability or consequences of an accident previously evaluated.
This proposed change revises the SR 3.3.7.a allowable values of the degraded voltage function. This proposed change will allow SCE to re-establish 218 kV as the minimum voltage on the offsite transmission grid necessary to support operability of the immediate access offsite power source (also referred to as the normal preferred power source). This will be accomplished by lowering the dropout and pickup settings, including allowable values for dropout and pickup of the degraded voltage protection relays. Following approval of this proposed change, the 4.16 kV Class 1E buses would be capable of remaining on the normal preferred power source at or above a grid voltage of 218 kV while protecting all Class 1E equipment from degraded grid conditions.
The degraded voltage protection circuits are designed to protect electrical equipment against the effects of degraded voltage on the offsite transmission networks. Therefore, these circuits are generally not considered to be accident initiators. However, spurious actuation of the degraded voltage protection relays could result in the loss of the preferred power source (offsite source of alternating current (AC) power). The proposed change lowers the allowable values for both dropout and pickup for the degraded voltage protection relays. This results in an increase in operating margin and a lower probability of spurious actuation of these degraded voltage signals. Therefore, there is no increase in the probability of a LOOP (preferred power source) as a result of this proposed change.
The safety function of the degraded voltage protection circuits is to ensure the operability of Class 1E equipment. SCE has performed calculations that demonstrate that operation in accordance with this proposed change will not result in operation of plant equipment at degraded voltages. Therefore, there is no increase in the consequences of any accident previously evaluated.
- 2. The proposed change will not create the possibility of a new or different kind of accident from any accident previously evaluated.
The proposed allowable values of the degraded voltage relays will provide an acceptable level of protection for plant equipment.
This proposed change affects only the voltage settings of the degraded voltage protection relays. There is no other change to the degraded voltage function. There are no physical modifications necessary to the degraded voltage protection relays. There are no changes to the actions performed by the relays following actuation. Therefore, there are no new failure modes or effects introduced by this proposed change.
Therefore, this proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.
- 3. The proposed change will not involve a significant reduction in a margin of safety.
The proposed degraded voltage protection schemes are designed to ensure that plant equipment will not operate at a degraded voltage. The proposed degraded voltage allowable values will not affect the existing protection criterion for plant equipment. This maintains the existing margin of safety for plant equipment.
Therefore, there is no significant reduction in the margin of safety as a result of the proposed amendment.
4.0 STATE CONSULTATION
In accordance with the Commission's regulations, the California State official was notified of the proposed issuance of the amendment. The State official had no comments.
5.0 ENVIRONMENTAL CONSIDERATION
The amendments change 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 amendments involve 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 amendments involve no significant hazards consideration, and there has been no public comment on such finding published June 14, 2005 (70 FR 34506). Accordingly, the amendments meet 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 amendments.
6.0 CONCLUSION
The NRC staff has reviewed the information in the licensees amendment request and the responses to the staffs request for additional information and concluded that the requirements of GDC 17 will be fulfilled via implementation of this amendment and it is, therefore, acceptable provided the modifications identified in this amendment are completed. The staffs conclusion is based on the following:
(1)
The results of the analyses confirm that all essential loads will have adequate voltage to perform their design function and the 4.16 kV Class 1E bus will remain connected to the normal offsite power source as long as the switchyard voltage remains at or above 218 kV.
(2)
The results of the analyses confirm that all essential loads will have adequate voltage to perform their design function and the 4.16 kV Class 1E bus will remain connected to the normal offsite power source as long as the switchyard voltage remains at or above 219.5 kV.
(3)
The criteria used to determine degraded voltage relay setpoint are adequate.
(4)
The assumptions, loading, and results of the analysis are adequate.
(5)
The pickup and dropout allowable values of DGV relays have been calculated in accordance with the current SCE setpoint calculation methodology with margins comparable to allowable value tolerance.
(6)
During channel calibration and functional test, the DGV relays will be reset within the as-left acceptance band.
(7)
TSTF recommendations will be evaluated for incorporation when available.
In addition, by letter dated July 1, 2005, the licensee stated that (1) the final proposed option (218 kV) will be implemented without first implementing the proposed interim setpoint for operation at 219.5 kV, and (2) the 120-V evaluation has been completed and it identified two additional tests that must be completed prior to implementation of the final proposed option (218 kV).
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) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.
Principal Contributors: O. Chopra A. Pal S. Mazumdar Date: July 1, 2005
April 2005 San Onofre Nuclear Generating Station Units 2 and 3 cc:
Mr. Daniel P. Breig, Plant Manager Nuclear Generation Southern California Edison Company San Onofre Nuclear Generating Station P. O. Box 128 San Clemente, CA 92674-0128 Mr. Douglas K. Porter Southern California Edison Company 2244 Walnut Grove Avenue Rosemead, CA 91770 Mr. David Spath, Chief Division of Drinking Water and Environmental Management P. O. Box 942732 Sacramento, CA 94234-7320 Chairman, Board of Supervisors County of San Diego 1600 Pacific Highway, Room 335 San Diego, CA 92101 Eileen M. Teichert, Esq.
Supervising Deputy City Attorney City of Riverside 3900 Main Street Riverside, CA 92522 Mr. Gary L. Nolff Power Projects/Contracts Manager Riverside Public Utilities 2911 Adams Street Riverside, CA 92504 Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011-8064 Mr. Michael Olson San Diego Gas & Electric Company P.O. Box 1831 San Diego, CA 92112-4150 Mr. Ed Bailey, Chief Radiologic Health Branch State Department of Health Services Post Office Box 997414 (MS7610)
Sacramento, CA 95899-7414 Resident Inspector/San Onofre NPS c/o U.S. Nuclear Regulatory Commission Post Office Box 4329 San Clemente, CA 92674 Mayor City of San Clemente 100 Avenida Presidio San Clemente, CA 92672 Mr. Dwight E. Nunn, Vice President Southern California Edison Company San Onofre Nuclear Generating Station P.O. Box 128 San Clemente, CA 92674-0128 Mr. James D. Boyd, Commissioner California Energy Commission 1516 Ninth Street (MS 31)
Sacramento, CA 95814 Mr. Ray Waldo, Vice President Southern California Edison Company San Onofre Nuclear Generating Station P.O. Box 128 San Clemente, CA 92764-0128 Mr. Brian Katz Vice President, Nuclear Oversight and Regulatory Affairs.
San Onofre Nuclear Generating Station P.O. Box 128 San Clemente, CA 92764-0128
San Onofre Nuclear Generating Station Units 2 and 3 cc:
Mr. Steve Hsu Department of Health Services Radiologic Health Branch MS 7610, P.O. Box 997414 Sacramento, CA 95899 Adolfo Bailon Field Representative United States Senator Barbara Boxer 312 N. Spring St. Suite 1748 Los Angeles, CA. 90012