ML070640060

Issuance of Amendment No. 203 Removal of Operating Mode Restrictions for Performing Emergency Diesel Generator Surveillance Testing

ML070640060
Person / Time
Site:	Columbia
Issue date:	03/23/2007
From:	Lyon C NRC/NRR/ADRO/DORL/LPLIV
To:	Parrish J Energy Northwest
Lyon C Fred, NRR/DORL/LPL4, 301-415-2296
Shared Package
ML070640057	List: ML070640060 ML070640065
References
TAC MD2113
Download: ML070640060 (13)

Text

March 23, 2007 Mr. J. V. Parrish Chief Executive Officer Energy Northwest P.O. Box 968 (Mail Drop 1023)

Richland, WA 99352-0968

SUBJECT:

COLUMBIA GENERATING STATION - ISSUANCE OF AMENDMENT RE: REMOVAL OF OPERATING MODE RESTRICTIONS FOR PERFORMING EMERGENCY DIESEL GENERATOR SURVEILLANCE TESTING (TAC NO. MD2113)

Dear Mr. Parrish:

The Nuclear Regulatory Commission (NRC) has issued the enclosed Amendment No. 203 to Facility Operating License No. NPF-21 for the Columbia Generating Station. The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated May 22, 2006, as supplemented by letter dated February 5, 2007.

The amendment revises TS surveillance requirements 3.8.1.11, 3.8.1.12, 3.8.1.16, and 3.8.1.19 to allow performance of the associated testing of the High-Pressure Core Spray Division 3 diesel generator (DG) during Modes 1, 2, and 3. The mode restrictions remain applicable for the Division 1 and Division 2 DGs.

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,

/RA/

Carl F. Lyon, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-397

Enclosures:

1. Amendment No. 203 to NPF-21

2. Safety Evaluation cc w/encls: See next page

Pkg ML070640057 (Amdt./License ML070640060, TS Pgs ML070640065) *memo dated 3/1/07 OFFICE LPL4/PM LPL4/LA EEEB/BC ITSB/BC OGC - NLO LPL4/BC NAME FLyon LFeizollahi** GWilson* TKobetz* TCampbell DTerao DATE 3/16/07 3/12/07 3/1/07 3/16/07 3/20/07 3/21/07 Columbia Generating Station cc:

Mr. W. Scott Oxenford (Mail Drop PE04) Mr. Dale K. Atkinson (Mail Drop PE08)

Vice President, Technical Services Vice President, Nuclear Generation Energy Northwest Energy Northwest P.O. Box 968 P.O. Box 968 Richland, WA 99352-0968 Richland, WA 99352-0968 Mr. Albert E. Mouncer (Mail Drop PE01) Mr. William A. Horin, Esq.

Vice President, Corporate Services/ Winston & Strawn General Counsel/CFO 1700 K Street, N.W.

Energy Northwest Washington, DC 20006-3817 P.O. Box 968 Richland, WA 99352-0968 Mr. Matt Steuerwalt Executive Policy Division Chairman Office of the Governor Energy Facility Site Evaluation Council P.O. Box 43113 P.O. Box 43172 Olympia, WA 98504-3113 Olympia, WA 98504-3172 Ms. Lynn Albin Mr. Douglas W. Coleman (Mail Drop PE20) Washington State Department of Health Manager, Regulatory Programs P.O. Box 7827 Energy Northwest Olympia, WA 98504-7827 P.O. Box 968 Richland, WA 99352-0968 Technical Services Branch Chief FEMA Region X Mr. Gregory V. Cullen (Mail Drop PE20) 130 228th Street, S.W.

Supervisor, Licensing Bothell, WA 98201-9796 Energy Northwest P.O. Box 968 Ms. Cheryl M. Whitcomb (Mail Drop PE03)

Richland, WA 99352-0968 Vice President, Organizational Performance & Staffing/CKO Regional Administrator, Region IV Energy Northwest U.S. Nuclear Regulatory Commission P.O. Box 968 611 Ryan Plaza Drive, Suite 400 Richland, WA 99352-0968 Arlington, TX 76011-4005 Assistant Director Chairman Nuclear Safety and Energy Siting Division Benton County Board of Commissioners Oregon Department of Energy P.O. Box 190 625 Marion Street, NE Prosser, WA 99350-0190 Salem, OR 97301-3742 Senior Resident Inspector Special Hazards Program Manager U.S. Nuclear Regulatory Commission Washington Emergency Management Div.

P.O. Box 69 127 W. Clark Street Richland, WA 99352-0069 Pasco, WA 99301 March 2007

ENERGY NORTHWEST DOCKET NO. 50-397 COLUMBIA GENERATING STATION AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 203 License No. NPF-21

1. The Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment by Energy Northwest (licensee) dated May 22, 2006, as supplemented by letter dated February 5, 2007, 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 and paragraph 2.C.(2) of Facility Operating License No. NPF-21 as indicated in the attachment to this license amendment.

3. The license amendment is effective as of its date of issuance and shall be implemented within 45 days from the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

David Terao, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to Facility Operating License and Technical Specifications Date of Issuance: March 23, 2007

ATTACHMENT TO LICENSE AMENDMENT NO. 203 FACILITY OPERATING LICENSE NO. NPF-21 DOCKET NO. 50-397 Replace the following pages of the Facility Operating License No. NPF-21 and Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain vertical lines indicating the areas of change.

Facility Operating License REMOVE INSERT Technical Specification REMOVE INSERT 3.8.1-10 3.8.1-10 3.8.1-11 3.8.1-11 3.8.1-15 3.8.1-15 3.8.1-16 3.8.1-16 3.8.1-17 3.8.1-17

(3) 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; (4) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source of special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (5) 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.

(6) Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to store byproduct, source and special nuclear materials not intended for use at Columbia Generating Station. The materials shall be no more than 9 sealed neutron radiation sources designed for insertion into pressurized water reactors and no more than 40 sealed beta radiation sources designed for use in area radiation monitors. The total inventory shall not exceed 24 microcuries of strontium-90, 20 microcuries of uranium-235, 30 curies of plutonium-238, and 3 curies of americium-241.

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 The licensee is authorized to operate the facility at reactor core power levels not in excess of full power (3486 megawatts thermal). Items in Attachment 1 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. 203 and the Environmental Protection Plan contained in l Appendix B, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

a. For Surveillance Requirements (SRs) not previously performed by existing SRs or other plant tests, the requirement will be considered met on the implementation date and the next required test will be at the interval specified in the Technical Specifications as revised in Amendment No. 149.

Amendment No. 203

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 203 TO FACILITY OPERATING LICENSE NO. NPF-21 ENERGY NORTHWEST COLUMBIA GENERATING STATION DOCKET NO. 50-397

1.0 INTRODUCTION

By application dated May 22, 2006 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML061520485), as supplemented by letter dated February 5, 2007 (ADAMS Accession No. ML070440139), Energy Northwest (the licensee) requested changes to the Technical Specifications (TSs) for the Columbia Generating Station (CGS). The requested change would revise TS 3.8.1, AC [Alternating Current] Sources - Operating, Surveillance Requirements (SRs) pertaining to testing of the Division 3 diesel generator (DG-3).

Specifically, the proposed changes will eliminate the specific mode restrictions for performance of SRs, which are currently prohibited during Modes 1, 2 or 3 for DG-3. This would allow the performance of SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.16, and SR 3.8.1.19 for DG-3 during any plant operating mode.

The supplemental letter dated February 5, 2007, 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 July 18, 2006 (71 FR 40745).

2.0 REGULATORY EVALUATION

The staff used the following Nuclear Regulatory Commission (NRC) requirements and guidance document to review the licensees amendment request:

! Title 10 of the Code of Federal Regulations (10 CFR), Appendix A of Part 50, General Design Criterion (GDC) 17, Electric power systems, requires, in part, 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 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 . . . 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.

! GDC 18, Inspection and testing of electric power systems, requires, in part, that Electric power systems important to safety shall be designed to permit appropriate periodic inspection and testing of important areas and features . . .

! Section 50.63 of 10 CFR, Loss of all alternating current power, requires, in part, that Each light-water-cooled nuclear power plant licensed to operate must be able to withstand for a specified duration and recover from a station blackout as defined in §50.2 . . .

! Paragraph 50.65(a)(3) of 10 CFR 50.65, Requirements for monitoring the effectiveness of maintenance at nuclear power plants, requires, in part, that Performance and condition monitoring activities and associated goals and preventive maintenance activities shall be evaluated at least every refueling cycle provided the interval between evaluations does not exceed 24 months . . .

Adjustments shall be made where necessary to ensure that the objective of preventing failures of structures, systems, and components through maintenance is appropriately balanced against the objective of minimizing unavailability of structures, systems, and components due to monitoring or preventive maintenance.

! Regulatory Guide (RG) 1.9, Selection, Design, Qualification, and Testing of Emergency Diesel Generator Units Used as Class 1E Onsite Electric Power Systems at Nuclear Power Plants, provides guidance for DG testing.

The NRC staff previously approved similar amendment requests for Perry Nuclear Power Plant (ADAMS Accession No. ML021840236), Clinton Power Station (ADAMS Accession No. ML003756900), and River Bend Station (ADAMS Accession No. ML030760726).

3.0 TECHNICAL EVALUATION

3.1 Description of CGS AC Electrical Power System The Class 1E AC distribution system at CGS supplies electrical power to three divisional load groups, Divisions 1, 2, and 3, with each division powered by an independent Class 1E 4.16 kilovolts (kV) engineered safety feature (ESF) bus. The Division 1 and 2 - 4.16 kV ESF buses have two separate and independent offsite sources of power. The Division 3 - 4.16 kV ESF bus has one dedicated offsite source of power. Each ESF bus has a dedicated onsite DG. The ESF systems of any two of the three divisions provide for the minimum safety functions necessary to shut down the unit and maintain it in a safe shutdown condition.

Offsite power is supplied to the CGS switchyard from two transmission interconnection points.

From these two substations, two electrically and physically separated circuits (preferred and backup sources) provide AC power to the Division 1 and 2 critical 4.16 kV ESF buses, while one qualified (230 kV) circuit supplies offsite power to the Division 3 ESF bus. The offsite AC electrical power sources are 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. An offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class 1E ESF buses.

DG-3, which is the High-Pressure Core Spray (HPCS) DG, has the capability to restore power quickly to the HPCS bus in the event offsite power is unavailable and to provide all required power for the startup and operation of the HPCS pump motor in a manner compatible with the safe shutdown of the plant. The HPCS DG starts and connects to the bus automatically on a bus undervoltage signal from the plant protection system. The failure of DG-3 does not negate the capability of other onsite power sources (Division 1 and 2 DGs). The licensee stated that procedures are in place to prevent paralleling of DG-3 with the normal transformer so that the short-circuit capability of the switchgear is not exceeded. The licensee stated that it is capable of periodic exercising of DG-3 under load. To accomplish this periodic exercising, the supply of the Division 3 - 4.16 kV Class 1E bus is transferred to the startup source. Under this condition, DG-3 is synchronized to the 230 kV offsite source and loaded via manual adjustment of the unit voltage and speed controls.

The CGS electrical distribution system is further described in the CGS Final Safety Analysis Report (FSAR), Chapter 8, Section 8.3, Onsite Power System.

3.2 Evaluation of Proposed Changes For SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.16, and SR 3.8.1.19, the licensee proposes to revise the Notes to remove the mode restrictions for DG-3, which would allow performance of the testing during any mode of operation.

SR 3.8.1.11 requires testing to verify that upon actuation of an actual or simulated Loss of Offsite Power (LOOP) signal, emergency buses de-energize and the HPCS DG auto-starts and energizes loads from a standby condition. As part of the SR, the Division 3 - 4.16 kV bus is disconnected from offsite power and re-energized from DG-3, at which point acceptable performance parameters of DG-3 are verified. The LOOP is simulated by opening the offsite power-supply breaker causing a dead bus condition and isolation of the HPCS electrical subsystem from the other two station electrical subsystems; therefore, the licensee stated, no system perturbation is expected. The NRC staff reviewed the information provided by the licensee in its application, as supplemented, and in the CGS FSAR, and concludes that there is reasonable assurance that no electrical system perturbation will occur during performance of the SR on DG-3.

SR 3.8.1.12 requires testing to verify that upon actuation of an actual or simulated Emergency Core Cooling System (ECCS) initiation signal, each required DG auto-starts and operates for $

5 minutes unloaded, the permanently connected loads remain energized from the offsite power system, and the emergency loads are auto-connected to the offsite power system. During the

surveillance, the HPCS system is in full-flow test mode with suction from and discharge to the condensate storage tank (CST). Once system flow is established, an ECCS signal is generated. The licensee stated in its February 5, 2007, supplement, that the ECCS signal is generated with an ECCS test switch connected to a main control room panel. Upon receiving the ECCS signal, the HPCS motor and DG-3 start. The HPCS motor is energized from the offsite power system. DG-3 runs unloaded for $ 5 minutes while voltage and frequency are verified. The starting of the HPCS motor is bounded by the AC distribution system analysis; therefore, the licensee stated, no system perturbation is expected. The NRC staff reviewed the information provided by the licensee in its application, as supplemented, and in the CGS FSAR, and concludes that there is reasonable assurance that no electrical system perturbation will occur during performance of the SR on DG-3.

SR 3.8.1.16 requires testing to verify that each required DG can (1) be synchronized with the offsite power source while loaded with emergency loads, and (2) upon a simulated restoration of offsite power, transfer all loads to an offsite power source and return to ready-to-load operation. This surveillance is performed following SR 3.8.1.19. Administrative controls and the paralleling of one DG at a time to the offsite power system ensures Division 1 and 2 operability; therefore, the licensee stated, no perturbations on the electrical system are expected. The NRC staff reviewed the information provided by the licensee in its application, as supplemented, and in the CGS FSAR, and concludes that there is reasonable assurance that no electrical system perturbation will occur during performance of the SR on DG-3.

SR 3.8.1.19 requires testing to verify that upon actuation of an actual or simulated LOOP signal in conjunction with an actual or simulated ECCS initiation signal, each DG automatically starts from standby condition and supplies power to permanently connected loads and auto-connected emergency loads for $ 5 minutes. This test is performed following SR 3.8.1.12. The ECCS signal is applied in conjunction with a simulated LOOP. Subsequently, DG-3 starts, the offsite power supply to the Division 3 ESF bus auto trips, and the licensee verifies that DG-3 supplies permanently connected loads for $ 5 minutes. Furthermore, the HPCS motor will start and be powered by DG-3. All loads on the HPCS bus are isolated from other plant loads and, therefore, the licensee stated, there is no perturbation to the other two divisional load groups.

Furthermore, the voltage and frequency of the HPCS bus are maintained by the DG-3 governor and voltage regulator during this test. The NRC staff reviewed the information provided by the licensee in its application, as supplemented, and in the CGS FSAR, and concludes that there is reasonable assurance that no electrical system perturbation will occur during performance of the SR on DG-3.

Currently, SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.16, and SR 3.8.1.19 contain a Note that precludes their performance during Modes 1, 2, or 3, with the provision that credit can be taken for unplanned events that satisfy the SRs, including post-corrective actions that require performance of this surveillance to restore this component to an operable state. The licensee proposes to remove the mode restrictions for DG-3 for these SRs. The TS Bases state that the reason for the mode restriction for SR 3.8.1.12 is to prevent unnecessary perturbations to the electrical distribution systems, which could challenge steady-state operation and, thus, plant safety systems, if this SR were performed with the reactor critical. For SRs 3.8.1.11, 3.8.1.16, and 3.8.1.19, the TS Bases state that the reason for the restriction is that performing the SRs would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge plant safety systems.

The HPCS system is a stand-alone system with a dedicated DG and independent electrical system. The HPCS system is designed and constructed to allow active components to be tested during any mode of plant operation. Specifically, the HPCS system has a full-flow test line to either the suppression pool or the CST, which allows testing without injecting water into the reactor vessel. Furthermore, the licensee stated that during HPCS testing, the Division 1 and 2 electrical buses will be powered from the main generator through the normal transformer.

These features, along with the design of the electrical distribution system, facilitate safe performance of testing pursuant to the subject SRs in Modes 1, 2, or 3. Therefore, since the safety buses will be powered from an electrically isolated source, the licensee stated that there will be no perturbation of the safety buses during the testing. In addition, the licensee stated that the possibility of sustained undervoltage is not considered credible due to response characteristics of the voltage regulator and protection equipment. The licensee also stated that the standby liquid control (SLC) system is not affected due to the fact that the SLC is connected downstream of the HPCS injection valve; therefore, performing the SRs during power operation will not challenge safety systems. The NRC staff reviewed the information provided by the licensee in its application, as supplemented, and in the CGS FSAR. Since the HPCS is a stand-alone system and the SLC is not affected during the performance of the SRs, the NRC staff finds that the performance of these SRs during Modes 1, 2, and 3 will not disrupt power operation, challenge safety systems, or appreciably increase the potential of causing a perturbation on the electrical distribution system.

In its February 5, 2007, supplement, the licensee stated that, during HPCS testing, it would perform SRs 3.8.1.11, 3.8.1.12, 3.8.1.16, and 3.8.1.19 with (1) the HPCS bus aligned to the 230 kV offsite power source via the startup transformer, and (2) with the Division 1 and 2 electrical buses powered from the main generator through the normal transformer. This configuration provides for sufficient independence of the onsite power sources from offsite power while still enabling testing to demonstrate DG operability. In addition, to prevent the injection of water into the reactor vessel during online testing, the licensee will utilize the key-locked override switch for the HPCS injection valve to prevent the valve from automatic stroking in response to an injection signal.

The NRC staff concludes that the licensee has provided reasonable assurance that the performance of the SRs on DG-3 during power operation (i.e., Modes 1, 2, and 3) would cause no perturbation on the electrical distribution system. Therefore, the staff concludes that the proposed changes to the CGS TSs will continue to satisfy requirements of GDC 17 and GDC 18, and the proposed TS changes are acceptable.

3.3 Conclusion Based on the above evaluation, the staff concludes that the proposed changes to CGS TS SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.16, and SR 3.8.1.19 are consistent with the applicable regulations; therefore, the proposed changes are acceptable.

4.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Washington State official was notified of the proposed issuance of the amendment. The State official had no comments.

5.0 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 and changes SRs.

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 (71 FR 40745; published on July 18, 2006). 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.

6.0 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) 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 Contributor: S. Ray, NRR Date: March 23, 2007