ML14010A317

Final Safety Analysis Report, Amendment 62, Appendix I - Licensing Review Group Issues

ML14010A317
Person / Time
Site:	Columbia
Issue date:	12/30/2013
From:	Energy Northwest
To:	Office of Nuclear Reactor Regulation
Shared Package
ML14010A476	List: GO2-13-174, Final Safety Analysis Report, Amendment 62, Appendix J - Shielding Evaluation Report ML14010A290 ML14010A291 ML14010A292 ML14010A293 ML14010A294 ML14010A295 ML14010A296 ML14010A297 ML14010A298 ML14010A299 ML14010A300 ML14010A301 ML14010A302 ML14010A303 ML14010A304 ML14010A305 ML14010A306 ML14010A307 ML14010A308 ML14010A309 ML14010A310 ML14010A311 ML14010A312 ML14010A313 ML14010A314 ML14010A315 ML14010A316 ML14010A317
References
GO2-13-174
Download: ML14010A317 (67)

Text

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 Appendix I LICENSI N G REVIEW GROUP ISSUES

TABLE OF CONTE N TS Section Page LDC N-9 9-0 0 0 I-i I.1 INTRODUCTION

..........................................................................

I.1-1 I.2 CONTAINMENT SYSTEMS BRANCH CSB-1 STEAM BYPASS OF THE SUPPRESSION POOL........................I.2-1 CSB-2 POOL DYNAMIC LOCA AND SRV LOADS...............................I.2-1 CSB-3 CONTAINMENT PU RGE SYSTEM..........................................I.2-2 CSB-4 COMBUSTIBLE GAS CONTROL............................................I.2-2 CSB-5 CONTAINMENT LEAK AGE TESTING......................................I.2-2

I.3 CORE PERFORMANCE BRANCH CPB-1 LOAD ASSESSMENT OF FUEL ASSEMBLY COMPONENTS..........I.3-1 CPB-2 WATERSIDE CORROSION...................................................I.3-1 CPB-3 CHANNEL BOX WEAR........................................................I.3-2 CPB-4 FUEL CLADDING, SWELLING, AND RUPTURE MODELS...........I.3-2 CPB-5 FISSION GAS RELEASE.......................................................I.3-3 CPB-6 STABILITY ANALYSIS.........................................................I.3-3 CPB-7 CHANNEL BOX DEFLECTION..............................................I.3-4

I.4 INSTRUMENTATION AND CONTROL SYSTEMS BRANCH ICSB-1 PHYSICAL SEPARATION AND ELECTRICAL ISOLATION...........I.4-1 ICSB-2 ANTICIPATED TRANSIENT WITHOUT SCRAM (ATWS)..............I.4-1 ICSB-3 TEST TECHNIQUES..........................................................I.4-2 ICSB-4 SAFETY SYSTEM SETPOINTS..............................................I.4-2

ICSB-5 DRAWINGS.....................................................................I.4-3 ICSB-6 RCIC CLAS SIFICATION.....................................................I.4-3 ICSB-7 SAFETY-RELATED DISPLAY...............................................I.4-3 ICSB-8 ROD BLOCK MONITOR.....................................................I.4-4 ICSB-9 MSIV LEAKAGE CONTROL SYSTEM.....................................I.4-5

C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 Appendix I LICENSI N G REVIEW GROUP ISSUES

TABLE OF CONTENTS (Continued)

Section Page LDC N-0 2-0 0 0 I-ii I.5 MATERIALS ENGINEERING BRANCH MTEB-1 PRESERVICE AND INSERVICE INSPECTION OF CLASS 1, 2, AND 3 COMPONENTS PER 10 CFR 50.55a(g).......I.5-1 MTEB-2 EXEMPTIONS FROM APPENDIX G AND H TO 10 CFR 50.......I.5-1 MTEB-3 EXEMPTIONS FROM APPENDIX G AND H TO 10 CFR 50.......I.5-1 MTEB-4 REACTOR TESTING AND COOLDOWN LIMITS.....................I.5-2 MTEB-5 GENERAL DESIGN CRITERION 51.....................................I.5-2

I.6 MECHANICAL ENGINEERING BRANCH MEB-1 ASYMMETRICAL LOCA AND SSE AND ANNULUS PRESSURIZATION LOADS ON REACTOR VESSEL

INTERNALS AND SUPPORTS..............................................I.6-1 MEB-2 PREOPERATIONAL VIBRATION ASSURANCE PROGRAM..........I.6-5 MEB-3 DYNAMIC RESPONSE COMBINATION USING THE SRSS TECHNIQUE...................................................................I.6-5 MEB-4 OBE PLUS SRV FA TIGUE ANALYSIS.....................................I.6-9 MEB-5 STRESS CORROSION CRA CKING OF STAINLESS STEEL COMPONENTS - DESIGN MODIFICATION.............................I.6-9 MEB-6 PUMP AND VALVE OPERABILITY ASSURANCE PROGRAM.......I.6-10 MEB-7 BOLTED CONNECTIONS FOR SUPPORTS.............................I.6-11 MEB-8 PUMP AND VALVE INSERVICE TEST PER 10 CFR 50.55a(g)......I.6-17 MEB-9 REVIEW OF IN SITU TEST PROGRAM OF THE SAFETY/RELIEF VALVE.....................................................

I.6-17 MEB-10 CRACKING OF JET PUMP HOLD-DOWN BEAMS....................I.6-18 MEB-11 CONTROL ROD DR IVE RETURN LINE..................................I.6-18 MEB-12 CONFIRMATORY PI PING ANALYSIS.....................................I.6-19

I.7 POWER SYSTEMS BRANCH PSB-1 LOW OR DEGRADED GRID VOLTAGE..................................I.7-1 PSB-2 TEST RESULTS FOR THE DIESEL GENERATORS....................I.7-1 PSB-3 CONTAINMENT ELECTRIC AL PENETRATIONS.......................I.7-2 PSB-4 ADEQUACY OF THE 120 V AC RPS POWER SUPPLY...............I.7-3 C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 Appendix I LICENSI N G REVIEW GROUP ISSUES

TABLE OF CONTENTS (Continued)

Section Page I-i i i PSB-5 THERMAL OVERL OAD MARGIN..........................................I.7-3 PSB-6 RELIABILITY OF DI ESEL GENERATOR.................................I.7-4 PSB-7 PERIODIC DIESEL GEN ERATOR TESTING............................I.7-5 I.8 REACTOR SYSTEMS BRANCH RSB-1 INTERNALLY GENERA TED MISSILES...................................I.8-1 RSB-2 CONTROL R OD SYSTEM....................................................I.8-1 RSB-3 SAFETY/RELIEF VALVES...................................................I.8-2 RSB-4 TRIP OF RECIRCULATION PU MPS TO MITIGATE ATWS..........I.8-2 RSB-5 DETECTION OF INTE RSYSTEM LEAKAGE.............................I.8-3 RSB-6 REACTOR CORE ISOLATION COOLING PUMP SUCTION.........I.8-3 RSB-7 SHUTDOWN UNINTENTIONALLY OF THE REACTOR CORE ISOLATION COOLIN G SYSTEM...........................................I.8-3 RSB-8 RHR ALTERNATE SHUTDOWN DEMONSTRATION..................I.8-4 RSB-9 CATEGORIZATION OF VALVES WHICH ISOLATE RHR FROM REACTOR COOL ANT SYSTEM....................................I.8-4 RSB-10 AVAILABLE NET POSI TIVE SUCTION HEAD..........................I.8-4 RSB-11 ASSURANCE OF FI LLED ECCS LINE....................................I.8-5 RSB-12 OPERABILITY OF ADS......................................................I.8-6 RSB-13 LEAKAGE RATE TESTING OF VALVES USED TO ISOLATE REACTOR COOLANT SYSTEM.............................................

I.8-6 RSB-14 OPERABILITY OF ECCS PUMPS..........................................I.8-6 RSB-15 ADDITIONAL LOCA BREAK SPECTRUM...............................I.8-7 RSB-16 LOCA ANALYSIS..............................................................I.8-8 RSB-17 OPERATOR ACTION, ANALYSIS OF CRACK IN THE RHR LINE.......................................................................I.8-9 RSB-18 LOCA ANALYSIS - DIVERSION OF LOW PRESSURE COOLANT INJECTIO N SYSTEM...........................................I.8-12 RSB-19 FAILURE OF F EEDWATER HEATER.....................................I.8-14 RSB-20 USE OF NONRELIABLE EQUIPMENT IN ANTICIPATED OPERATIONAL TRANSIENTS..............................................

I.8-14 RSB-21 USE OF NON-SAFETY GRADE EQUIPMENT IN SHAFT SEIZURE ACCIDENT.........................................................

I.8-14 RSB-22 ATWS.............................................................................I.8-15 C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 Appendix I LICENSI N G REVIEW GROUP ISSUES

TABLE OF CONTENTS (Continued)

Section Page I-iv RSB-23 PEACH BOTTOM TURBIN E TRIP TESTS................................I.8-16 RSB-24 MCPR............................................................................I.8

-16 RSB-25 GEXL COR RELATION........................................................I.8-17 RSB-26 STABILITY EVALUATION...................................................I.8-17 RSB-27 SCRAM DISCH ARGE VOLUME............................................I.8-17 RSB-28 SRV SURVEILLANCE.........................................................

I.8-18 C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 Appendix I LICENSI N G REVIEW GROUP ISSUES

LIST OF TABLES

Number Title Page LDC N-0 1-0 0 0 I-v MEB-1-1 Load Combination and A cceptance Criteria for ASME Code Class 1, 2, and 3 NSSS P i ping and Equip m en t...........................

I.6-3

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 Appendix I LICENSI N G REVIEW GROUP ISSUES

LIST OF FIGURES

Number Title I-vi I.8-1 Vessel Pressure Versus Time for a Cr ack in the RHR Line I.8-2 Water Level Versus Time for a Crack in the RHR Line

I.8-3 Peak Cladding Temperat ure Versus Time for a Crack in the RHR Line

I.8-4 HTC at PCT Node Versus Time for a Crack in the RHR Line C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 9-0 0 0 I.1-1 I.1 INTRODUCTION

The italicized information is historical and was provided to support the application for an operating license.

The Licensing Review Group (LRG) was formed in April 1980 to provide a vehicle for expediting the licensing process for General Electric (GE) boili ng water reactors (BWR). The group was made up of six utilities, GE, and the consulting firm of KMC. Membership was at both the executive and technical level.

All applicants were in the near-term operating license (NTOL) st age of the licensing process.

The basis of establishing the LRG consisted of the fact that most issues for NTOL BWR plants are identical or very similar. It was fe lt that this common gr ound could be used advantageously in the NRC review process. The NRC assigned a Project Licensing Manager to interface with the LRG.

All utilities represented in the LRG are identified below. Th e plants indicated are ordered chronologically in the licensing process, with LaSalle County-1 being the first for which NRC issued a Safety Evaluation Report (SER).

Plant Utility LaSalle County-1 Commo nwealth Edison Company

Zimmer Cincinnati Gas and Electric Company

Shoreham Long Island Lighting Company

Susquehanna-1 Pennsylvania Power and Light Company

Fermi-2 Detroit Edison Company

Columbia Generating Station Energy Northwest

The LRG worked on a lead plant concept with LaSalle County-1 acting as the lead plant.

Subsequent to the issuance of the SER for La Salle, NRC issued SERs for Zimmer, Shoreham, Susquehanna, and Fermi (refer to References 1 through 5).

Interface with staff from various branches of NRC identified issues for the specific branches. Often, the issues consisted of a question or questions previously developed by NRC. Whenever possible, a common position on the issue was developed which was applicable to all plants. In some cases, however, uniqueness of design or other variables precl uded a common position.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.1-2 Plant unique positions we re then developed. This appe ndix is for Columbia Generating Station, but uses common positions when applicable.

The order of presentation for an issu e is as follows: The issue is presented, then the details of the issue follow under the "Question" heading.

The response is then given. The numbers in parentheses (e.g., 5.4.4 , 6.2) reference the applicable secti ons in the FSAR. Applicable questions are referenced as appropriate since in many instances th e issue was previously addressed in a Columbia Genera ting Station question response.

References:

1. U.S. Nuclear Regulatory Commission (N RC), NUREG-0519, "Safety Evaluation Report by the Office of Nuclear Reactor Regula tion in the Matter of Commonwealth Edison Company, LaSalle County Station, Units No. 1 and 2," Dockets No. 50-373/374.

2. NRC, NUREG-0528, Supplement No. 1, "SER by the Office of Nuclear Reactor Regulation, NRC, in the Matter of Cincinnati Gas and Electric Company, William H. Zimmer Nuclear Power Station, Unit 1," Docket No. 50-358.

3. NRC, Office of Nuclear Reactor Regul ation, NUREG-0420, "SER Related to the Operations of Shoreham Nuclear Power St ation, Unit No. 1, Docket No. 50-322, Long Island Lighting Company," April 1981.

4. NRC, Office of Nuclear Reactor Regulati on, NUREG-0776, "SER Re lated Operation of Susquehanna Steam Electric St ation, Units 1 and 2, Docket s No. 50-387 and 50-388, Pennsylvania Power and Light Company, Allegheny Elect ric Cooperative, Inc.," April 1981.

5. NRC, Office of Nuclear Reactor Regul ation, NUREG-0798, "SER Related to the Operation of Enrico Fermi Atomic Powe r Plant, Unit No. 2, Docket No. 50-341, Detroit Edison Company et al.," July 1981.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.2-1 I.2 CONTAIN M ENT SYSTEMS BRANCH ISSUE: CSB-1 STEAM BYPASS OF THE SUPPRESSION POOL

(6.2.1.1)

Question:

The applicant approach to suppres sion pool bypass is not consis tent with Branch Technical Position CSB 6-5. The applicant must commit to perform a low power surveillance leakage test of the containment at each refueling outage.

Response:

The response to above stated concern is pr ovided in response to Question 031.070.

ISSUE: CSB-2 POOL D Y N A MIC LO C A AND SRV LOADS

Question:

The staff has completed its re view of the short-term program and developed acceptance criteria. We require that the applicant commit to our acceptance criteria or justify any exceptions taken.

Response:

NRC acceptance criteria as well as the supplem ents thereto are being reviewed and adhered to where possible. Where exceptions are taken, such as in the case of SRV load definition (see Reference 1), or chugging load de finition (see Reference 2), these exceptions are being discussed and reviewed with the staff.

References:

1. "SRV Loads - Improved Definition and Application Methodology for Mark II Containments" (submitted in August 1980).

2. "Chugging Loads - Revised Definition and Applicati on Methodology for -Mark II Containments" (based on 4TCO Test Results) (submitted in July 1981).

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.2-2 ISSUE: CSB-3 CONTAINMENT PURGE SYSTEM

Question:

A 2-inch vent line exists in the purge system to bleed off exces s primary containment pressure during operation. We require the applicant to evaluate this 2-in ch bypass purge system in light of the criteria of Branch Technical Position CSB 6-4.

Response:

The 2-inch bypass valves, used for pressure control during oper ation, are located in parallel with each purge system exhaust valve. These 2 inch-150# globe valves meet all the design requirements of the containment isolation system. They are de signed to the same pressure/temperature ratings of the containment and purge va lves and are designed to close within 4 sec against the 45 psig containment design pressure. All four bypass valves can be remotely operated from the control room, ar e designed to close an F, A, and Z isolation signals and are being operationally qualified against applicable seismic and hydrodynamic loads.

ISSUE: CSB-4 COMBUSTIBLE GAS CONTROL

(6.2.5)

DELETED

ISSUE: CSB-5 CONTAINMENT LEAKAGE TESTING

DELETED C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 9-0 0 0 I.3-1 I.3 CORE PERFORMANCE BRANCH

ISSUE: CPB-1 LOAD ASSESSMENT OF FUEL ASSEMBLY COMPONENTS

Question:

The proposed addition of Appendix A to SRP 4.

2 provides guidance for the analysis of fuel assembly components and acceptance criteria for fuel assembly response to externally applied forces. The applicant's fuel assembly capability should be asse ssed accordingly.

Response:

General Electric has complete d development of fuel assemb ly loads modeling and results acceptance criteria both deemed to be in accordance with the requirements of Appendix A to SRP 4.2. The LRG lead plant (LaSalle) has be en evaluated accordingly with acceptable results, which were fo rwarded to the NRC June 8, 1981. A similar analysis will be performed for Columbia Generating Station (CGS).

ISSUE: CPB-2 WATERSIDE CORROSION

Question:

The applicant has not addressed the potential for fuel corrosion failure similar to that which occurred at the Vermont Yankee plant.

Response:

As indicated in the General Electric presentation given to the NRC in December 1979, the failures appeared to be associated with a metallic incursion in the feedwater. This event has occurred only once in th e BWR operating history and is unlikely to reoccur.

Subsequent to this event, Ge neral Electric provided an operation recommendation for corrosion product control which should preclude this type of event at CGS.

Energy Northwest plans to employ those General Electric operating reco mmendations which have been proven to be effective at several operating BW R plants for maintaining water quality parameters at or below GE's water quality specification limits.

References

1. Letter from R. E. Engel (GE) to M. Tokar (NRC), MFN-172-80, "Corrosion Product Control", dated October 3, 1980.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.3-2 ISSUE: CPB-3 CHANNEL BOX WEAR

Question:

Provide more detailed and specific informa tion on the Channel Box Wear concern as applicable to the CGS design.

Response: General Electric observed wear on the water rods in 8 x 8R fu el assemblies in the fall of 1979.

In the referenced lett er it was concluded that the observed wear does not affect the functionality of the water rods in the bundle or plant safety.

Since the observed wear General Electric has modified the 8 x 8R water rod design. To improve the margin of re liability of the 8 x 8R fuel design, a modification to the water rod and spacer positioning/water rod has been developed. This modified design has shorter water rod and spacer positioning/water r od lower end plugs, and modifie d expansion springs on the

upper end plugs. These changes have been shown to be effective by successful ope ration of the short shank 8 x 8 fuel design and from extensive flow-induced vibr ation testing. This modified water rod concept is being installed on new fuel , such as for CGS, as a prudent means of assuring increased margin of fuel reliability. Thus, the modification does not constitute an unreviewed safety question to CGS based on the criteria given in 10 CFR 50.59.

Reference:

1. Letter, J. S. Charnley (GE) to T. A.

Ippolito (NRC), "Water Rod Lower End Plug Inspection Results," dated July 28, 1980.

ISSUE: CPB-4 FUEL CLADDING, SWELLING, AND RUPTURE MODELS

Question:

The applicant has not provided info rmation to assure that for the fuel cladding in a LOCA "the degree of swelling and incidence of rupture are not underestimated" as required by Appendix K of 10 CFR 50.46. The pr ocedures proposed in NUREG-0630 introduce additional conservatism and should be utilized to perform s upplemental calculations to the current ECCS analyses.

Response:

General Electric recently transmitted supplemental calculations to the NRC, "Fuel Swell and Rupture Model - Experimental Data Review and Sensitivity Studi es," May 15, 1981. This C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.3-3 document contains a discussion of the first stre ss and circumferential strain data applicable to the BWR, and presents results from the se nsitivity studies performed comparing the NUREG-0630 models with the current GE models.

Hoop stress versus rupture temperat ure sensitivity studies were performed using a combination of the two curves (adjusted GE stress curve and NUREG-0630). These st udies resulted in a change in PCT of +/-10°F. Even though this PCT impact is small, GE proposes to review the

current stress model to incor porate the adjusted curve. Impl ementation of the adjusted curve will be coincidental with implementation of the complete LOCA model improvement package.

Also, the document shows that NUREG-0630 perforation strain versus temp erature curve is not applicable to BWR fuel and that substitution of a bounding NUREG-0630 curve into the current GE ECCS analysis has ne gligible effect on the peak cl ad temperature (PCT). Based on this, it is maintained that the current GE strain model is valid for the BWR and should continue to be used for ECCS calculations at CGS.

Reference:

1. Letter, R. H. Buchholz (GE) to L. S. Rubenstein (NRC), "General Electric Fuel Clad Swelling and Rupture Model," dated May 15, 1981.

ISSUE: CPB-5 FISSION GAS RELEASE

Question:

Provide more detailed and specific informa tion on the Fission Gas Release concern as applicable to the CGS design.

Response:

The effects of high burnups an d subsequent fission gas releas e on fuel thermal-mechanical design analyses was addressed in the proprietary General Electri c presentation to the NRC on Extended Burnups, March 24, 1981. Burnups to 50 GWd/MT are considered in the stress analyses documented in NEDE-24011-PA. This analysis is applicable to CGS fuel.

ISSUE: CPB-6 STABILITY ANALYSIS

Question:

Please refer to NRC Questi on 221.009 for this question.

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 9-0 0 0 I.3-4 Response:

Please refer to the response to NRC Question 221.009.

ISSUE: CPB-7 CHANNEL BOX DEFLECTION

Question: The applicant has not referenced General Electric Licensing Topical Report NEDE-21354-P which describes the fuel channel design. Of specific concern is the commitment to control rod driveline friction testi ng recommended in Section 4.4.2 of NEDE-21354-P.

Response:

To resolve the channel box defle ction issue, Energy Northw est has initiated a channel management program for CGS. The elements of this program include:

a. Compiling complete operating history re cords for each channe

l. Data to be collected include channel location, orient ation of welded sides, exposure, and control history.

b. Compiling complete analytical history records for each c hannel including fast fluence (>1 MeV) , and flux gradient history.

c. Measurement of post-opera tion channel box deflection.

Energy Northwest is planning to measure channel box deflection after each refueling outage for selected channels which are di scharged to the spent fuel pool. The reuse of discharged channels will be determined based upon these me asurements as compared to predetermined criteria. Other items which will be addressed in this program include development of channel manufacturing history data and an alytical, predictive capability.

The Channel Management Program has already resulted in so me potential improvement in channel operation. Data from Commonwealth Edison measurements wh ich recently became available indicate that major channel bow may be a strong function of channel manufacturing history rather than location of the channel within the core.

Their data indicate that prime candidates for channel bow are ma nufactured from two pieces of stock material not from the same original material batch. Also, Commonwealth Edison channels which experienced major bow, in many cases, were never on the core periphery.

Based on this information, Energy Northwest has identified which of the CGS channels are manufactured from mismatched halves (75 out of 764) and we have set up special plans to C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 9-0 0 0 I.3-5 manage the use of these channels to minimize potential channel bow. These measures include taking advantage of core locati ons which are not adjacent to control blades and, in addition, identification of locations of mi nimal exposure and fast flux tilt.

In addition to the above channel management program, Energy Northwest is proposing to take a number of operational actions to monitor channe l distortion in the core. Prior to startup after each reload, scram time testing and rod notch testing will be performed. For rods which fail the above test, the pressure test descri bed in NEDE-21534-P (4.4.2) will then be performed.

C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 LDC N-0 2-0 0 0 I.4-1 I.4 INSTRUMENTATION AND CONTROL SYSTEMS BRANCH

ISSUE: ICSB-1 PHYSICAL SEPARATION AND ELECTRICAL ISOLATION (7.1.4, 7.2.3, and 7.6.3)

Question:

In the applicant's design, Class 1E instrume ntation do not adhere to adequate separation criteria, have not been qualified, and do not adhere to separation of Class 1E to non-Class 1E instrumentation.

Response:

Columbia Generating Station (CGS) Class 1E instrumentation has been reevaluation to the requirements NUREG-0588, Category II, as described in the Equipment Qualification Report referenced in 3.11. Class 1E instrumentation is adequ ately separated as described in the response to Question 031.100 and as additionally agreed to in CGS docket letter GO2-81-146, dated June 18, 1981.

ISSUE: ICSB-2 ANTICIPATED TRANSIENT WITHOUT SCRAM (ATWS)

Question:

We require that the applicant agrees to implement plant modifications on a scheduled basis in conformance with the Commission's final resolution of ATWS. In the even t that LaSalle starts operation before necessary plant modifications are implemen ted, we require some interim actions be taken by LaSalle in order to reduce, further, the risk from ATWS events.

The applicant will be required to:

a. Develop emergency procedures to train operators to recognize an ATWS event, including consideration of scram indicators, rod position indicators, flux

monitors, vessel level and pr essure indicators, relief valve and isolation valve indicators, and containment temperature, pressure, and radiation indicators.

b. Train operators to take action in the event of an ATWS including consideration of immediately manual scramming the re actor by using the manual scram buttons followed by chan ging rod scram switches to the scram position, stripping the feeder breakers on the reacto r protection system power distribution buses, opening the scram discharge volume drain valve, prompt actuation of the C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 I.4-2 standby liquid control system, and prompt placement of the RHR in the pool cooling mode to reduce the severity of the containment conditions.

Response:

See the response to RSB-22.

ISSUE: ICSB-3 TEST TECHNIQUES (7.1.4)

Question:

In order to perform routine survei llance testing, it is necessary for the applicant to pull fuses.

We consider that this design does not satisfy the requirements of IEEE Standard 279-1971, Paragraphs 4.11 and 4.20.

Response:

The responses to Questions 031.

039 and 031.061 address this issue.

Part (b) of the response to Question 031.039 is repeated below:

"In no instance will it be necessary during testing... to either lift leads or remove fuses."

ISSUE: ICSB-4 SAFETY SYSTEM SETPOINTS

(7.1.4)

Question:

The range of Class 1E system sensors may be exceed ed in the worst case combination of setpoint and accuracy.

Response: a. All calculated setpoints (taking into account drift) will be within sensor range and will be in accord with T echnical Specification Limits.

b. Certain setpoints are dependent upon actual plant location or operation (i.e., background radiation) and c an only be determined at a later date. If an incompatibility exists with regard to sensor range the instrument will be replaced. This position applies for all in struments where con flicts are detected.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.4-3 ISSUE: ICSB-5 DRAWINGS

Question:

The one line drawings and schema tics contradict the functional control drawings and system description which are provided in the FSAR. Furt hermore, contact utiliza tion charts contradict the actual schematics.

Response:

The contradiction between the draw ings and the system descriptions has been eliminated as the result of a major effo rt spent in rewriting Chapter 7 with this concern in mind. With regard to inconsistencies between the f unctional control diagrams and schematics, all FSAR drawings and those listed in Chapter 1.7 are upd ated and distributed every 6 months.

ISSUE: ICSB-6 RCIC CLASSIFICATION

Question:

Refer to Question 031.015 and LRG Issue RSB-6.

Response:

Refer to responses to Question 031.015 and LRG Issue RSB-6.

ISSUE: ICSB-7 SAFETY-RELATED DISPLAY

(7.5)

Question:

The design of the safe shutdown indication does not satisfy the requirements of IEEE Standard 279-1971, Paragraph 4.10.

Response: CGS safety-related display instru mentation will be designed to co mply with the requirements of Regulatory Guide 1.97, Revision 2. Section 7.5 has been amended to discuss the degree of conformance for CGS for each indication applic able as described in Regulatory Guide 1.97 and IEEE Standard 279-1971.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.4-4 ISSUE: ICSB-8 ROD BLOCK MONITOR (7.6)

Question:

The applicant does not agree that the rod block monitor is a protection system.

Response: The NRC has conducted an extensive review of the RMCS including refueling interlocks RBM, RWM, RSCS on various dockets. Plants with open items having sim ilar designs will be conformed to the Zimmer design (i.e., the resolution will be reviewed and resolution bases if applicable will be incorporated).

The Zimmer design review has been completed and the issue resolv ed. This closure basis will be relied upon. CGS system is similar to the design proposed for the Zimmer plant as delineated below:

a. The four flow monitors are interconnect ed by armored cabl e and shield cables and there are open spaces around the c ables which penetrate fire barriers between redundant channels.

b. Both rod block monitor channels ar e connected by data buses which are enclosed in a metal shield and ru n along the top of the cabinet.

c. The wiring of the rod block monitor by pass switch satisfies the CGS separation criteria.

d. The rod block monitor is a modified design and contains mu ltiplexing circuitry which interfaces with the new reactor manual control system.

Items a, b, and c have been ver ified at CGS site as to their existence. The NRC met with General Electric on Item d. and the staff has approved the current design and transient analysis with the addition of periodic technical specification testing to assure system operability.

• CGS will include a surveillance requireme nt in the Technical Specification for the rod block monitor.

• A GE/NRC generic meeting was held in Be thesda on January 22, 1981 to discuss the new reactor manual control system utilized on most NTOL plants. The NRC has been concerned for many years about the appropriateness of utilizing the RBM (not fully safety grade) in transient mitigation.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.4-5 ISSUE: ICSB-9 MSIV LEAKAGE CONTROL SYSTEM

Question:

We identified a single failure to the MSIV leakage control syst em which could lead to possible failure of the system dur ing testing or operation.

Response: Please see the revised re sponse to Question 031.076.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.5-1 I.5 MATERIALS ENGINEERING BRANCH ISSUE: MTEB-1 PRESERVICE AND INSERVICE INSPECTION OF CLASS 1, 2, AND 3 COMPONENTS PER 10 CFR 50.55a(g)

Question:

Preservice and inservice inspec tion of Class 1, 2, and 3 com ponents have not been submitted.

Response: The response to the above stated concern is pr ovided in the respons e to Question 121.010.

ISSUE: MTEB-2 EXEMPTIONS FROM APPENDIX G AND H TO 10 CFR 50 MTEB-3 (5.1.4) (5.3.2) (5.3.3)

Question:

The Columbia Generating Station (CGS) reactor vessel does not meet the specific requirements of Appendix G and H to 10 CFR 50. Identify and justify your exemptions.

Response:

CGS, as a member of the Licensing Review Group (LRG), has submitted information of fracture toughness and surveill ance program requirements to show compliance with Appendix G and H t o 10 CFR 50.

This submittal (Refere n ce 1) w a s similar to that which has been approved by the NRC for the preceding LRG members (LaSalle County, Susquehanna, Shoreham, Zimmer, and Fermi-2).

Reference:

1. Letter GO2-81-532, G. D. Bouchey to A. Schwencer, "Appendix G and H Information, Responses to Materials Engineering Branch - Component Integrity Section," dated December 18, 1981.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.5-2 ISSUE: MTEB-4 REACTOR TESTING AND COOLDOWN LIMITS (5.3)

Question:

Insufficient information has been submitted for us to assess that the methods used to provide stress intensity values, are equivalent to t hose obtained from Appendix G of ASME Code; clarification and justification of the methods used to construct the operating pressure temperature limits s hould be provided.

Response:

CGS has provided information to show comp liance with the methods of Appendix G of Section III of the ASME Boiler and Pressure C ode (Summer 1972 Addenda). Compliance with Appendix G for this vessel is to provide operating limitations on pressure and temperature based on fracture toughness. These operating limits assure that a margin of safety against a nonductile failure of this vessel is the same as that for a vessel built to the Summer 1972 Addenda.

The specific temperature limit s for operation when the core is critical are based on an approved modification to 10 CFR 50, Appendix G, Paragraph IV.A.2.c. The approved modification and justification for it is given in GE Licensing Topical Report NEDO-21778-A (Reference 1).

See Refere n c e 1 t o MEB-2 and M E B-3.

Reference:

1. Letter to Dr. G. G. Sherwood (GE) from Olan V. Parr (NRC), "Review of General Electric Topical Report, Transient Pressu re Rises Affecting Fracture Toughness Requirements for Boiling Water Reactors," November 13, 1978 (see GE Transmittal

T-1727).

ISSUE: MTEB-5 GENERAL DESIGN CRITERION 51

Question:

The applicant must demonstrate that the primar y containment pressure boundary at CGS meets the requirements of General Design Criterion 51 of 10 CFR 50.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.5-3 Response: GDC-51 requires that under ope rating, maintenance, testin g, and postulated accident conditions (1) the ferritic ma terials of the containment pressure boundary behave in a non-brittle manner and (2) the probability of rapidly propagating fracture is minimized.

The CGS containment system includes a ferritic steel primary containment vessel and head enclosed by a reinforced concrete shield structure. The ferri tic materials of the containment pressure boundary that we re considered in the evaluation for compliance to GDC-51 are those that have been applied in the fabrication of th e containment vessel and he ad, equipment hatch, personnel lock, and penetrations and components of the fluid sy stem including valves required to isolate the system. These components are the parts of th e containment system that are not backed by concrete and must sust ain loads during the performan ce of the containment function under the conditions cited by GDC-51.

CGS containment pressure boundary is comprised of ASME Code Class I, Class 2, and MC components. Based upon the review performed by the NRC, it was determined that the fracture toughness requirements in ASME Code Editions and Addenda typi cal of those used in the design of the CGS containment may not ensure compliance with GDC-51 for all areas of the containment pressure boundary.

The basis for this decision was that the fracture toughness criteria that had been applied in construction differ in Code classifications and Code Edition and Addenda. Therefore, the Class I, Class 2, and Class MC components of the CGS containment pressure boundary were reviewed according to the fracture toughness requirements of the Summer 1977 Addenda of Section III for Class 2 components and fracture toughness data presented in NUREG-0577, "P otential for Low Fracture Toughness and Lamellar Tearing of PWR Steam Generato r and Reactor Coolant Pump Supports."

Based on review of the available fracture t oughness data and material f abrication histories, and the use of correlations betw een metallurgical characteri stics and material fracture toughness, it was concluded t hat the ferritic materials in the CGS containment pressure boundary meet the fracture toughness requirements that are sp ecified for Class 2 components by the 1977 Addenda of Section III of the ASME Code. Co mpliance with these Code requirements provide reasonable assurance t hat the CGS reactor containment pressure boundary materials will behave in a non-brittle manner, that the probability of rapidly propagating fracture will be minimized, and that the require ments of GDC-51 are satisfied.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-1 I.6 MECHANICAL ENGINEERING BRANCH ISSUE: MEB-1 ASYMMETRICAL LOCA AND SSE AND ANNULUS PRESSURIZATION LOADS ON REACTOR VESSEL INTERNALS AND SUPPORTS (3.9.2)

Question: Document your reevaluation of the safety-related systems and components based upon the load combinations, response combina tion methodology, and acceptance cr iteria required by us as presented at our meeting of December 12, 1978. (Reference letter dated September 18, 1978.)

Response:

This issue was discussed at the Mechanical Engineering Branch (M EB) Safety Evaluation Report (SER) meeting held September 29 throug h October 1, 1981, for Columbia Generating Station (CGS). Load combinations and acceptance criteria are provided in the responses to the MEB SER questions 23 and 25, pres ented at that meeting (see Table MEB-1-1

). Results of the reevaluation will be provided in the New Loads update of 3.9 , to be provided in a future amendment.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 1-0 0 0 I.6-3 Table MEB-1-1 Load Combination a nd Acceptance Criteria for ASME C ode Class 1, 2, and 3 NSSS Piping and Equipment

Load Co m b ination Design Basis Ev aluation Basis (Service Level)

N + SRV(ALL) Upset Upset (B) N + OBE Upset Upset (B) N + OBE + SRV(ALL) Emergency Upset (B) N + SSE + SRV(ALL) Faulted Faulted*

(D) N + SBA + SRV Emergency Emergency*

(C) N + IBA + SRV Faulted Faulted* (D) N + SBA + SRV(ADS) Emergency Emergency*

(C) N + SBA + OBE + SR V (ADS) Faulted Faulted* (D) N + IBA + OBE + SR V (ADS) Faulted Faulted* (D) N + SBA/IBA + SSE + SR V (AD S) Faulted Faulted* (D) **N + L O C A + SSE Faulted Faulted* (D) LOAD D E FINITION LEGEND Normal (N)

- Normal and/or abnormal loads depending on a cceptance criteria.

OBE - Operational basis earthquake load

s.

SSE - Safe shutdown earthquake loads.

SRV - Safety/relief valve dis c harge induced loads from two adja c ent valves (one valve actuated when adjacent valve is cyc l ing).

SRV A L L - The loads induced by actuation of a l l safety/relief valves which activate within milliseconds of each other (e.g., turbine trip operational transient).

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 1-0 0 0 I.6-4 Table MEB-1-1 (Continued)

SRV ADS - The loads induced by the actuation of safety/relief valves associated with automatic depressurization system which activate within milliseconds of each other during the postulated small or intermediate size pipe rupture.

LOCA - The loss-of-coolant accident associat ed with the postulated pipe rupture of large pipes (e.g., main steam, feedwater, recirculation piping).

LOCA 1 - Pool swell drag/fallout loads on piping and components located between the main vent discharge outlet and the suppression pool water upper surface.

LOCA 2 - Pool swell impact loads on piping and components located above the suppression pool wate r upper surface.

LOCA 3 - Oscillating pressure induced loads on submerged piping and components during condensation oscillations.

LOCA 4 - Building motion induced loads from chugging.

LOCA 5 - Building motion induced loads from main vent air clearing.

LOCA 6 - Vertical and horizontal loads on main vent piping.

LOCA 7 - Annulus pressurization loads.

SBA - The abnormal transients associated with a small break accident.

IBA - The abnormal transients associated with an intermediate break accident.

• All ASME Code Class 1, 2, and 3 piping syst ems which are required to function for safe shutdown under the postulated events shall meet the requirements of NRC's "Interim Technical Position Function Capability of Passive Components" - by MEB.

• • The most limiting case combination among LOCA 1 through LOCA

7.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-5 ISSUE: MEB-2 PREOPERATIONAL VIBRATION ASSURANCE PROGRAM (3.9.2 , 3.9.5) Question:

Additional information is required concerning the basis for the allowable vibration amplitude derived and clarification of the use of twice this allowable is acceptable.

Response:

This item has been closed by M EB prior to LRG review. It is not documented in lead plant or subsequent plant SERs. For additional information see responses to Questions 110.022, 110.023, and 110.024.

ISSUE: MEB-3 DYNAMIC RESPONSE COMBINATION USING THE SRSS TECHNIQUE

Question:

We are studying the problem of utilizing the s quare-root-of-the-sum-of-the-squares (SRSS) for determining responses other t han LOCA and SSE as you have used. By not utilizing the absolute sum method, the review may be extended if we do not agree that the SRSS methodology is applicable.

Response:

The response to this issue was provided during the Mechani cal Engineering Branch meeting for CGS, September 29 throug h October 1, 1981. (See Attachment 1

.)

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-7 ATTACH MENT 1 Question No. 26 (3.9.3.1)

The methods of combining responses to all of the loads requested in (a) above is required. Our position in this issue for Mark II plants is outlined in NUREG-0484, Revision 1, "Methodology for Combining Dynamic Responses". However, since the primary containment for the CGS plant is a free-standing steel pressu re vessel and the plant is in a higher seismic zone, the staff will require that the criteria in Section 4 of NUREG-0484, Revision 1, "Criteria for Combination of Dynamic Responses Other Than Those of SSE and LOCA," be satisfied if the square-root-of-the-sum-of-the-squares method of combining these responses is used. (Reference Regulatory Position E (2) in the enclosure to a letter from J. R. Miller, NRC, to Dr. G. G. Sherwood, GE, "Revi ew of General Electric Topica l Report NEDE-24010-P," dated June 19, 1980.) The conclusions of NUREG-0484, Revision 1, are based on the studies performed by GE in NEDE-24010-P and BNL in NUREG/CR-1330. The applicant must demonstrate that an SRSS combination of dynamic responses achieves the 84% nonexceedance probability level because of the difference in containment and seismic level which were not

included in the earlier studies.

Response:

When a seismic response from a high seismic input , like that from Hanford, is combined with another dynamic response (e.g., SRV discharge loads), dependi ng on the relative magnitudes of the two responses being combined, the shape of the cumulative distribution function (CDF) of the combined response will c hange. If the maximum magnitude of one of the responses is very large compared to the other response being combined, the CDF curve will almost be vertical and it is immaterial if these two res ponses are combined using the SRSS or the Absolute Sum (ABS) rule. However, if the maximum magnitudes of the two responses are about equal, use of SRSS vs. ABS rule to combine the responses will cause significant difference in the co mbined response. In addition, in this case, the CDF curve will be more like S-shaped with the non-exceedance probability (NEP) of SRSS being close to 84%. In the generic Mark II study, examples from both such cases were considered w ith more examples from the case with responses of comparable ma gnitudes. This study showed that all these Mark II cases meet the requirements of NUREG-0484. Hen ce the GE Topical Report NEDE-24010-P, "Technical Bases for the Use of SRSS Method for Combining Dynamic Loads for Mark II Plants," is also applicab le to CGS with high seismic input.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-8 The impact of the free-standing steel primary cont ainment is discussed in the areas as follows:

a. Vessel and Internals Vessel and internals are not attached to and not affected by the steel containment.

b. Piping Systems and Fl oor Mounted Equipment The dynamic input to these components at their containment support locations may be affected by the steel containment response to the dynamic loads under consideration and hence, may be differe nt from that obtai ned from concrete containment. However, the freque n c ies contri b u ting to the responses of major structures and components in both type s of plants will not be significantly different but will fall into the same general range.

The structural frequencies will only determine the magnitude of amplific ation or attenuation of the response. For multi-freque ncy random-type dynamic loads, the components of input loads whose frequencies coincide with the structural natural frequencies will be amplified and these components will dominate the response. Although the predominant respons e of a particular structural component may vary somewhat in frequency between the concrete and steel containment configuration, the va riances are expected to be small for the range of frequencies of interest for major structures because of the similarities in systems, types of structural configurations, construction materials, and massiveness of buildings. Therefore, key characteristics of the responses (duration of strong response motion and number of peaks) are primarily determined by the input component loads to the structure, and because of the

similarity of the dynamic nature of the input loads due to earthquake, SRV, and LOCA for both types of containment, their st ructural responses will have sim ilar dynamic char acteristics.

Hence, the response of the mechanical components and piping syst ems supported from the two types of containments will also be similar. Hence, the use of SRSS combinations for combining the dynamic responses for the CGS application will be demonstrated to meet the 84%

non-exceedance probability level.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-9 ISSUE: MEB-4 OBE PLUS SRV FATIGUE ANALYSIS Question:

Clarify your considerat ion of the cyclic loadings due to the operating basis earthquake (OBE) and safety/relief valve actuation in your NSSS fatigue analysis.

Response: For the NSSS piping, 50 peak OBE cycles ar e used. For other NSSS equipment and components, a generic study serves as the basis for 10 peak OBE cycles. As shown in Refe r e nce 1 , 10 peak OBE cyc l es can envelope t h e cumulative f a tigue damage of hundreds of less severe earthqua ke cycles. Section 3.9 of the FSAR was revised to reflect this position.

The methodologies used to eval uate the fatigue effects due to combined SRV and OBE loads are documented in Reference

2. In the fatigue analysis of NSSS equipment, piping, reactor pressure vessel, and RPV internal components, the actual calc ulated loads due to OBE and SRV are combined to show compliance with upset limits of fatigue.

References

1. Letter from R. Artigas to R. Bosnak, "Number of OBE Fa tigue Cycles in the BWR NSSS Design," September 17, 1981.

2. Letter from R. B. Johnson to R. Bosnak, "GE Position on Fatigue Analysis,"

June 29, 1981.

ISSUE: MEB-5 STRESS CORROSION CRACKING OF STAINLESS STEEL COMPONENTS - DESIGN MODIFICATION

Question:

You are requested to review all ASME Code Cl ass 1, 2, and 3 pressure boundary piping, safe ends and fitting material, including we ld metal at your facility to determine if the material selection, processing guidelines, or inspec tion requirements set forth in NUREG-0313, Revision 1, "Technical Report on Material Selec tion and Processing Guidelines for BWR Coolant Pressure Boundary Piping," are satisfied.

Response:

The response to the above stated concern is provided in the res ponse to NUREG-0313, Revision 1, which was submitted to the NR C September 2, 1981, via GO2-81-268, C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-10 G. D. Bouchey to A. Schwencer, "Hardshi p Exemption Request for Implementation of NUREG-0313, Revision 1."

ISSUE: MEB-6 PUMP A N D VALVE OPERABILITY ASS U RAN C E PRO G R AM (3.9.3.2)

Question: Additional information has been requested rega rding your analytical and testing methods for your pump and valve operab ility assurance program.

Response: a. Pumps In addition to the tests called for in the FSAR, active safety-related pumps have been analyzed to find the natural fre quencies of the pump. When these frequencies were above the ZPA of the seismic floor response spectra, static analyses were performed on the pumps. Wh en the analyses established that the resultant stresses in the pumps were below allowabl es and the deflections under these loads were less than clearances between moving parts, operability was established. No pumps have been identified which need to have additional testing or analysis to establish operability.

b. Valves

In addition to the tests mentioned in th e response to Question 110.032, seismic analyses have been and are be ing performed on the activ e safety-related valves which were not protot ypically tested. The tests, along with the analysis showing clearance at critical points, demonstrate operability under normal plus SSE loading.

Where the analyses do not show clearances, the valves are bei ng retested as part of the requalification program. If the test and/or analyses did not include hydrodynamic loads where applicable, th e valves are being retested or reanalyzed using the prope r loading as part of th e requalification program.

Where valve accelerations resulting from piping analyses are not yet known, the peak acceleration for frequencies over 8 hz on the 0.005 damp ing floor response spectra is used as input acceleration for valve analysis and testing. The acceptability of this criter ia are being established by comparing piping analysis accelerations to these pe aks. The test reports, analyses, and requalification C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-11 plans were made available and audited by the NRC-SQRT (Seismic Qualification Review Team) and NRC-PVORT (Pump and Valve Operability Review Team) during November 1982.

ISSUE: MEB-7 BOLTED CONNECTIONS FOR SUPPORTS

(3.9.3)

Question:

You have not provided the allowable limits for buckling for th e reactor vessel support skirt subjected to faulted conditions. In addition, we requested information concerning the design of support bolts and bolted connections.

Response:

The responses to Questions 24 (Attachment 1) and 42 (Attachment 2) from the CGS draft SER respond to this issue.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-13 ATTACHMENT 1

Question No. 24 (3.9.3.1)

Several references are made in Table 3.9.

2 (a) through 3.9.2(a c) to allowable stresses for bolting. Specifically, what loading combinations and allowabl e stress limits are used for bolting for (a) equipment anchorage, (b) component supports, and (c) flange connections. Where are these limits defined?

Response: a. Floor Mounted Equipment

1. Equipment Anchorage Bolting

The floor anchored mechanical equipment (pumps, heat exchangers, and

RCIC turbine) in GE's scope of s upply are mounted on a concrete floor or a steel structure. The design of concrete anchor bolts for the

equipment mounted on concrete floor , and the responsibility to prescribe and meet the necessary codes and stress limits are in the AE's scope of supply. The design of attachment bolts for the equipment mounted on steel structure, and the re sponsibility to prescrib e and meet the necessary codes and stress limits are also in th e AE's scope of supply. GE works with the interface limit of 10,000 psi in tension or shear for the only purpose of sizing bolt holes in the equipment base, based on the required nominal size and number of bolts for maximum loads.

2. Component Support Bolting

(a) RWCU Pump

The support bolting of this non-safe ty essential pump is designed for the effects of pipe load and SSE load to the requirements of the ASME code,Section III, Appendix XVII. The stress limits of 0.41Sy for tension and 0.15Sy for shear are used.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-14 (b) RCIC Turbine The pump-to-base plate bolti ng is designed as follows:

(1) Normal Plus Upset

a) Primary membrane:

1.0S b) Primary membrane plus bending:

1.5S,where S is the allowable stress limit

per the ASME Code Section III, Appendix I, Table 1-7.3.

(2) Emergency or Faulted

Stresses shall be less than 1.2 times the allowable limits for "Normal plus Upset" given above.

(c) Flanged Connection Bolting

There are no flange type connections in component supports.

b. Piping Supports and Pipe Mounted Equipment (Valves and Pump) Supports The supports are hanger and snubber type (including clamps) linear standard components as defined by the ASME C ode Section III, Subsection NF. The bolts used in these supports meet criteria of NF-3280 fo r Service Levels A and B and NF-3230 for Service Levels C and D. (N ote: NF-3280 is applicable to bolting for Service Levels A and B. NF-3230 is applicable to linear supports; it refers to Appendix VII which is applicable to bolting for Service Levels C and D.)

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-15 ATTACH MENT 2 Question No. 42 (3.9.3.4)

The applicant's response to NRC Question 110.029 is not completely acceptable.

Paragraph 3.9.3.4 impli e s that the reactor vessel support skirt was designed to an allowable compressive load of 0.8 ma terial yield stress. It is not cl ear how the applicant's design would meet the staff's acceptable allowable load of two-thirds of critical buckl ing load. In addition, the applicant has assumed the critical buckling stress as the material yield stress at temperature. Provide bas is for this assumption.

Response:

This issue was addressed and approved by the NRC on the Susquehanna DSER docket.

Refer to the response to Susquehanna DSER 3.9.3-6. A sim ilar response is provided as follows:

Per GE design specification, the permissible co mpressive load on the reactor vessel support skirt cylinder (plate and shell ty pe component support) was lim ited to 90% of the load which produces yield stress, divided by the safety factor for the condition being evaluated. The effects of fabrication and opera tional eccentricity was included.

The safety factor for faulted conditions was 1.125.

An analysis of reactor pressure vessel support skirt buckling fo r faulted conditions shows that the support skirt has the capability to meet ASME Code Section III, Paragraph F-1370(c) faulted condition limits of 0.

67 times the critical buckling strength of the support at temperature assuming that the cr itical buckling stress limit corre sponds to the material yield stress at temperature. The f aulted condition analyze d included the compressive loads due to the design basis maximum earthquake, the overturning moments and shears due to the jet reaction load resulting from a severed pipe, and the compressive effects on the support skirt due to the thermal and pressure expansion of the reactor vess el. The expected maximum earthquake loads for the Hanford 2 reactor vess el support skirt are less than 50% of the maximum design basis loads used in the buckling analysis describe d; therefore, the expected faulted loads are well below the critical buckling limits of Paragraph F-1370(c) for this reactor vessel support skirt. The expected earthquake loads for this reactor were determined using the seismic dynamic analysis met hods described in Section

3.7. Based

on currently defined faulted condition loads includi ng annulus pre ssurization and SSE

loads, the maximum compressive stress in the suppor t skirt for axial and bending loads is less than the upset condition allowables determined by the methods of NB-3133.6 of the ASME Code. This assures satisfactory margin against buckli ng for the faulted condition loads.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-17 ISSUE: MEB-8 PUMP A N D VALVE IN S ERVICE TEST PER 10 CFR 50.55a(g)

Question:

You have not submitted your proposed program for the inservice tes ting of pumps and valves as required by 10 CFR 50.55a(g).

Response: The CGS pump and valve inservice test program plant was submitted to the NRC via letter GO2-81-322, G. D. Bouchey to A. Schwencer, "Pump and Valve Test Program Plan," dated October 1, 1981.

ISSUE: MEB-9 REVIEW OF IN SITU TEST PROGRAM OF THE SAFETY/RELIEF VALVE

Question:

No specific question identified for this issue.

Response:

Extensive in-plant SRV actuati on test programs have been implemented at Caorso (Italy) and Tokai-2 (Japan), two BWR plants with Mark II containment configura tion and equipped with x-quenchers of a desi gn essentially identical to those used in CGS. Test results from the above programs, which are available to the NRC, have been used to develop an improved SRV discharge load definition for specific application to CGS (see Report, "SRV Loads, Improved Definition for Mark II Containments, Proprietary Sec tion") and to confirm that the difference between bulk pool temperature and loca l pool temperature at the quencher discharge is within the value assumed in the suppression pool temperature transient analysis for CGS. As stated in Reference 3, implementation of additional SRV tests to measure or confirm the adequacy of the SRV load definition is unnecessary, but an in-plant test to measure local to bulk pool temperature difference will be performed.

References:

1. Letter GO2-80-172, D. L. Renberger to B. J. Youngblood, "Submittal of SRV Report," dated August 8, 1980.

2. Letter, J. J. Verderber to B. J. You ngblood, "Submittal of Propr ietary SRV Report," dated August 27, 1980.

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 LDC N-9 9-0 0 0 I.6-18 3. Letter GO2-81-524, G. D. Bouchey to A. Schwencer, "Suppression Pool Temperature Transient Analysis and In-Plant SR V Test," dated December 15, 1981.

ISSUE: MEB-10 CRACKING OF JET PUMP HOLD

-DOWN BEAMS

Question:

Additional information is required concerning the actions being taken by the licensee to preclude cracking of the jet pump hold-down beams.

Response:

As discussed in response to IE Bulletin 80-07, CGS will comply with the GE generic resolution. Since the jet pump hold-down beams have already been installed, CGS will reduce the beam preload from 30 kips to 25 kips which is expected to increase beam operating time to crack initiation at the 2.5% probability level to a rang e of 19 to 40 years. Also, during operation, periodic inspections will be c onducted as part of our overall in-service inspection program. Inspection frequencies will be developed in th e future based on lead pl ant inspection results and the results of future testing at G e neral Electric. (See Reference 1.)

References:

1. Letter, G. D. Bouchey to R. L. Tede sco, GO2-80-279, "Cracking of BWR Jet Pump Hold Down Beams," dated December 4, 1980.

ISSUE: MEB-11 CONTROL ROD DRIVE RETURN LINE

Question:

We have not completed our revi ew of GE Topical Report NEDE-21821-2A addressing reactor feedwater nozzle/sparger design modification for cracks nor have we completed GE's generic modification to the control rod drive return no zzle. This may require additional request for information.

Response:

Energy Northwest's response to NUREG-06 19, "BWR Feedwater Nozzle and Control Rod Drive Line Nozzle Cracking," has been completed. The curren t status of our position on the CRD cracking problem is as follows:

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-19 a. CRD return line has been cut and capped as allowed by NU REG-0619, page 31.

b. CRD return line has been rerouted through redundant equalizing valves to the exhaust water header.

c. The control rod drive preoperational te st will demonstrate that the system is fully operational and that all compon ents including the hydraulic drive mechanisms, pumps, and flow control va lves function properly. The CRD system will be configured with the m odifications noted in the NRC concern.

d. In order to assure satisfactory system operation with the single failure of an equalizing valve, the proposed design modification will include the addition of

two equalizing valves installed in a paralle l configuration. The failure of either valve will not impair CRD operation for any foreseen operating or accident condition.

e. There will be no increased potential fo r carbon steel corrosi on products to be deposited in the drives. All lines in the CGS hydraulic system after the drive water filters are made of stainless steel.

f. The NRC requested GE by letter of January 28, 1980, to recalculate the makeup flow capacity for the 251-inch BWR-5 w ithout the CRD return line. This generic information has been provided by letter of Ma y 2, 1980, from R. L. Gridley, GE, to D. G. Eisenhut , NRC, concurrently with this docketed response for LaSalle. The results indicate that the 251-inch BWR-5 CRD system without a return line (capped Nozzle 10) can achieve a vessel makeup flow in excess of its calculated boiloff rate of 180 gpm. This confirms the same boiloff rate as previously documented in a March 14, 1979, submittal from GE. Furthermore, since the CRD system is not designed to perform an ECCS function, the additional testing to demons trate the required return flow capacity to the vessel is not warranted.

ISSUE: MEB-12 CONFIRMATORY PIPING ANALYSIS

Question: This item is comprised of two issues:

a. The NRC requires piping system data fo r the purpose of running confirmatory stress calculations to assure co mpliance with IE Bulletin 79-14.b.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-20 b. Documentation of the preoperational vibration test program for all ASME,Section III, Class 1, 2, and 3 high en ergy piping systems and all Seismic Category I portions of moderate and high energy piping systems.

Response: a. A summary of CGS inspection program and the design control measures utilized to assure an adequate design for the Seismic Category I piping systems are contained in a letter from D. L. Renberger to R. H. Engelken," WPPSS Nuclear Project No. 2, IE Bulletin 79-14," d a ted September 7, 1979 (Reference 1). Presently, CGS has an established program to develop as-built drawings

documenting the final configuration of th e piping systems toge ther with their supports. The preparation of the as-built drawings is currently underway and

these as-built drawings will provide the basis for the final design assessment of the piping systems. However, in order for NRC to proceed with the confirmatory piping analysis and to verify the compliance of the design data with the as-built configuration, Reference 3 provided t h e necessary piping design data as requested in Reference

2.

b. The preoperational/startup piping vibration program includes all Class 1, 2, and 3 high energy piping systems inside Se ismic Category I structures or those portions of high energy systems whose failures could adversely affect the functioning of safety-related structures, systems, or components. The program also includes all Seismic Category I porti ons of moderate energy piping systems outside containment.

All systems contained in the preope rational/startup vibration program, as documented in Section 14.2 , are operated at rated flow and the piping system is either visually inspected or monitored for steady st ate vibration by remote readout transducers. If during this initial system operation visual observation indicated that piping vibr ation is significant, measurements are made with a hand-held vibrograph. The results will then be reviewed by the appropriate engineering group to determine the accep tability of the measured vibration values. For the main steam, recirculation, feedwater, RCIC,and SRV discharging piping, the measured vibration is compared against test acceptance criteria. The results are also revi ewed by the responsible piping design organization to confirm proper system performance. Documentation of the test results and engineering evaluation perfor med on them becomes a part of the Startup Test Program files. A summ ary report is generated and would be available for NRC review following commercial operation.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.6-21

References:

1. Letter from D. L. Renberger to R. H. Engelken, "WPPSS Nuclear Project No. 2, IE Bulletin 79-14," dated September 7, 1979, GO2-79-156.

2. Letter from R. L. Tedesc o to R. L. Ferguson, "Confir matory Piping Analysis for WNP-2," dated J une 22, 1981.

3. Letter G. D. Bouchey to L. J. Auge (Manager, Energy Tec hnology Center), dated September 9, 1981, GO2-81-279.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.7-1 I.7 POWER SYSTEMS BRANCH ISSUE: PSB-1 LOW OR DEGRADED GRID VOLTAGE

Question:

The electrical system does not meet our requirements for pr otection under low or degraded voltage conditions.

Response: NRC requirements for protection under low or degraded voltage conditio ns are detailed in Question 040.036 which references revised 8.3.1.1.1 and 8.3.1.2.4.3.

ISSUE: PSB-2 TEST RESULTS FOR THE DIESEL GENERATORS (8.3.2)

Question:

Test results for the diesel generators to indicate marg in have not been submitted.

Response:

PSB-2 identifies two margin test s to be accomplished during the preoperational testing of the diesels. The first, a "steady-sta te margin test," involves loading the unit in excess of the total design accident loads to demons trate some margin over the to tal design requirements. The other test, a "start-load margin test," involves applying a step function load in excess of the largest motor to demonstrat e the start-load capability of the set with some margin.

Preoperational testing of Columbia Generating Station (CGS) em ergency diesels will include subjecting the diesels to 100% rated load as well as loading the units to their two-hour rating, both of which are larger than the combined design accident loads.

During the loss of power tests, occurring during th e preoperational testing phase, a test will be made to demonstrate the start-load capability of the units over that which is required. This test involves loading the diesel generator to 100%

design load and dropping the largest motor on the associated bus. This motor will then be restarted. This test demonstrates the diesel generator unit has the capability to start the largest moto r on its respective bus while concurrently feeding the rest of the bus loads and still remain within the voltage and frequency requirements of Regulatory Guide 1.9.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.7-2 The HPCS diesel gene rator will not be required to fulfill the requirements of Regulatory Guide 1.9, with respect to the voltage and frequency drop, during this particular test as clarified in 8.3.1.2.1.4. Preoperational test results will be available for NRC review during the normal inspection enforcement period.

ISSUE: PSB-3 CONTAIN M ENT ELECTRICAL PE N E TRATIO N S Question:

The reactor electrical penetrations do not conform to Regulator y Guide 1.63 and test results do not demonstrate that the electric al penetrations can maintain their integrity for maximum fault current.

Response:

NRC concerns regarding electric al penetration capab ility under maximum fault (short circuit) conditions are expressed in LaSalle FSAR Question 040.106. That question addresses the

effect upon containment inte grity of fault current i 2t, assuming failure of the circuit primary protective overcurrent device.

LaSalle's response took credit for the fusing properties of cabl e external to the penetration conductors to provide overcurrent protection backup to the primary overcurrent device. The response reflected a common Licensing Review Group (LRG) position.

The LaSalle SER rejects the LRG position, advis ing that credit cannot be given for assumed equipment failure (cable fusing). It mandates that fault current protection devices (circuit breakers and/or fuses) to backup the primary over-current protective devi ces be provided as required to limit fault current su rges to levels less than those for which the penetrations are qualified.

NRC concerns in this area are addressed to CGS in Questions 040.

031 and 040.035. These questions were not as explicit regarding the NRC concern as was the question addressed to LaSalle. The CGS response to Question 040.035 pr edated much of the NRC/LaSalle dialogue and requires revision.

The original response to Question 040.034 provided data indicating the capability of

penetration primary overcurrent protective devices to clear faults before penetration i 2 t capability is exceeded.

Additional analysis has been performed to determine the maximum i 2t available at electrical penetrations for the case of fa ilure of the circuit primary protective devices to function, which requires the backup overcurrent protective device to clear th e fault. Where the analysis C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 1-00A I.7-3 demonstrates that penetration i 2t capability is exceeded, a second overcurrent protective device has been added in series with the circuit primary overcurrent protective device.

The responses to Question 040.03 4 and 040.035 have been r evised to reflect th e results of this analysis.

ISSUE: PSB-4 ADEQUA C Y OF T H E 120 V AC RPS POWER SUPPLY (8.3.1.1.6)

Question:

The applicant committed to the gene ric resolution, or to expedite their license, wi ll commit to the surveillance requirements wh ich were applied to Hatch-2.

Response:

Energy Northwest is committed to implement, prior to fuel loading, the RPS MG set design modification developed by Gene ral Electric for generic applic ation. The FSAR has been revised to reflect th e design modification.

ISSUE: PSB-5 THERMAL OVERLOAD MARGIN

Question:

We require the applicant to provide the detaile d analysis and/or criteri a which was used to select setpoints for the therma l overload protection devices for valve motors in safety systems and the details as to how th ese devices will be tested.

Response:

Motor thermal overloads for Cl ass 1E motor-operated valves (MOVs) are chosen two sizes larger than those which would be required based upon normal full load running current. The resultant overload protection (approximately 140% of motor full load current) permits MOVs to operate for extended periods of time at moderate overloads; tripping occurs just prior to motor damage.

Class 1E motor control centers ar e located in environmentally controlled rooms such that overload ambient temperature variation is not a significant factor.

Initial testing of overload heaters serving safe ty-related MOVs is performed by Energy Northwest during the Test and Startup Program. This testing is accomplished by injecting a C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 I.7-4 test current through the overload device, thus, simulating an over current of the motor operator and verifying that the device stops valve travel by deenergizing th e motor starter and/or alarms at the appropriate alarm panel, as applicable. Acceptan ce criteria for thes e tests are derived by manufacturers' curves for the devices or applicable codes and standar ds where available.

Periodic surveillance testing of thermal overl oads serving safety-related MOVs will be in accordance with the CGS technical specifications. A re presentative sample of at least 25% will be tested at least once per 18 months, such that all will be tested once pe r six years. The test itself will be essentially the sa me as that described above.

ISSUE: PSB-6 RELIABILITY OF DIESEL GENERATOR

Question:

No specific question identified for this issue.

Response:

The reliability of starting and accepting design load in the required time was fully demonstrated for the Div. 1 and Div. 2 D-Gs by the successful completion of the 300 Start Qualification Test performed on D-G Unit 1 in accordance with NRC BT P-EICSB-2 prior to shipment. The reliability of the HPCS D-G has been verified by a prototype test on an eventually identical unit. See Reference

4.

In response to other concerns on the reliability of all the D-G units, see the responses to, Questions 040.080 through 040.089.

The HPCS D-G (Div. 3) has been given preoperational tests to demonstrate the reliability of starting and accepting design load in the requi red time, and that the system has adequate margin in all respects, such as starting time, accelerating time, engine torque, and long-term carrying capability.

The 300 Start Qualification Test Report for D-G Unit 1 is availabl e for the NRC's review at the plant site. See Reference

2.

The HPCS D-G (Div. 3) Site Pre operational Test Report is available to the NRC for review at the plant site. See Reference

3.

References

1. NRC Branch Technical Position EICSB-2

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.7-5 2. Prototype 300 Start Qualification Test Report, B&R File No. 53-00-7014 and 53-00-7015.

3. HPCS D-G Acceptance Test, PT-7.2-A

4. GE Document No. NEDO-10905-3, Licensing Topical Report-High-Pressure Core Spray System Power Supply Unit.

ISSUE: PSB-7 PERIODIC DIESEL GENERATOR TESTING Question:

Diesel generator testing on ce every 18 months is require d by Regulatory Guide 1.108.

Response:

The Technical Specifications for CGS comply with Regulatory Guide 1.108 requirements for testing the diesel generators on 18-month interval

s. In addition, a test has been included to verify that after an interruption of onsite power the loads are shed from the emergency buses and that subsequent loading of the onsite sources is through the load sequencer. See the response to Qu estion 040.037.

C OLUMBIA G ENERATING S TATION Amendment 59 F INAL S AFETY A NALYSIS R EPORT December2007 LDCN-06-000 I.8-1 I.8 REACTOR SYSTEMS BRANCH

ISSUE: RSB-1 INTERNALLY GENERATED MISSILES (3.5.1)

Question:

The applicant has not supplied the information to show that all safe ty-related systems and components within the containment, including th e containment, are protected from missiles.

With regard to missiles sizes of concern, what is the valve size below which, if failure should occur in a high pressure system, damage to ot her components within th e primary containment would not be significant? State cr iteria used to determ ine this size.

Identify all valves in the primary containment larger than this size and id entify the missile protec tion provided for each valve (either physical location or barrier).

Response All safety-related systems and components at Columbia Generating Station (CGS) are protected from credible plant. A response identifying criteria and methodology and the final results for

inside and outside containment in the th ird quarter of 1982 (let ter no. GO2-82-672).

Valve parts are not postula ted as credible missile sources if double retention features exist or bonnet bolting is shown to have high margins of safety. All valves in our plant were evaluated on this basis and it was concl uded that valves are not credible missile sources.

ISSUE: RSB-2 CONTROL ROD SYSTEM

(4.6.2)

Question:

As a result of eliminating the control rod drive system return line, we are reviewing generically with regard to the impact on control rod drive system performance. C onsequently, we require the applicant to submit system performance dat a directly applicable to CGS and will require the applicant to conform to the conclusion of the generic study as applicable to CGS.

Response:

See the response to MEB-11.

See also the revised response to Question 211.019.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November1998 I.8-2 References

1. Letter, G. G. Sherwood (GE) to E. G. Case (NRC), "Cont rol Rod Drive (CRD) Return Line Removal," dated January 27, 1978.

2. Letters, G. G. Sherwood (G E) to V. Stello (NRC) and R. J. Mattson (NRC), "Control Rod Drive (CRD) Return Line Removal," dated July 14, 1978.

3. Letters, G. G. Sherwood (G E) to V. Stello (NRC) and R. J. Mattson (NRC), "Control Rod Drive (CRD) Return Line Removal," dated February 22, 1979.

ISSUE: RSB-3 SAFETY/RELIEF VALVES

(5.2.2 and 6.3.2)

Question:

Additional information is required both for quali fication test and operati ng experience with the applicant's safety/relief valves.

Response:

The response to the above stated concern is provided in the revised response to Question 211.051. Also refer to response to Question 211.209.

ISSUE: RSB-4 TRIP OF RECIRCULATlON PUMPS TO MITIGATE ATWS

(5.2.2)

Question:

We require reperformance of the overpressure analysis to consider the effect of the ATWS RPT.

Response: Section 5.2.2 was revised as part of the ODYN analysis which has been submitted to the NRC.

This section incorporates the confirmatory analysis of the overpressure protection report including the ATWS recirculation pump trip. Also see revised response 15.8 and response to Question 211.049.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-3 ISSUE: RSB-5 DETECTION OF INTERSYSTEM LEAKAGE (5.2.5) Question:

We requested that the applicant show how it inte nds to detect leakage fr om the reactor coolant systems into both the low pressu re coolant injection (3 trains) and low pressure core spray systems as required by Regulatory Guide 1.45.

Response: Intersystem leakage will be detected by pressure instrument ation with control room readout in accordance with Regulatory Guide 1.45. The response to CGS FSAR Question 211.009 provides information on this issue.

ISSUE: RSB-6 REACTOR CORE ISOLATION COOLING PUMP SUCTION

Question:

The applicant must supply further information to determine whether the RCIC pump suction has to be automatically switched from the condensate storage tank to the suppression pool in the event of a safe shutdown earthquak e and concomitant failure of the condensate storage tank.

Response:

As stated in the response to Question 211.046, an automatic safety-grade switchover to a Seismic Category I supply (suppression pool) has been provided. A description of the automatic switchover has been provided in the response to Question 211.146.

ISSUE: RSB-7 SHUTDOWN UNINTENTIONALLY OF THE REACTOR CORE ISOLATION COOLING SYSTEM

Question:

Show how the design of the RCIC protection system prevents unintentional shutdown of the system, when the system is required, because of spurious ambient temperature signals from

areas in and around the system (especially in the RCIC pump room)

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-4 Response: See the revised respons e to Question 211.010.

ISSUE: RSB-8 RHR ALTERNAT E SHUTDOWN DEMONSTRATION

Question: The applicant must perform tests to show that flow through the sa fety/relief valves is adequate to provide the necessary fluid relief required consistent wi th the analyses reported in Section 15.2.9 of the FSAR.

Response:

Refer to the revised response to Question 211.025. Also, NUREG-O737, Item II D.1 is related to Issue RSB-8. A discussion on NUREG-O737 items is contained in Appendix B.

ISSUE: RSB-9 CATEGORIZATION OF VALVES WHICH ISOLATE RHR FROM REACTOR COOLANT SYSTEM (5.4.2)

Question:

We require that the valves which serve to isol ate the residual heat re moval system from the reactor coolant system be clas sified Category A/C in accor dance with the provisions of Section XI of the ASME code.

Response:

Please refer to RSB-13.

ISSUE: RSB-10 AVAILABLE NET POSITIVE SUCTION HEAD

Question:

The applicant must verify that the suction lines in the suppr ession pool leading to the ECCS pumps are designed to preclude adverse vortex formation and ai r injection which could effect pumps performance.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-5 Response: All ECCS suction lines in the suppression pool have been designed with large diameter piping (24 inches) to reduce inlet velocity. In the worst conceivable case, where there is a leak from an ECCS pump suction line into the largest of th e ECCS pump rooms, the water level in the suppression pool is calculated to equalize at elevation 455'-9". In the calculation, no credit is taken for makeup to the suppressi on pool nor for pumping water leak ing into the affected room/ suppression pool. The RCIC pump su ction is an 8-inch pipe. The submergence of the top edge of the suction piping with s uppression pool water level at 455 ft-9 in. is as follows:

Penetrations Depth (C.L.)

Submergence

RHR L oop "A" (X-35) 447'-0" 7.8' "B" (X-32) 447'-0" 7.8' "C" (X-36) 447'-7" 7.2' LPCS (X-34) 447'-7" 7.2' HPCS (X-31) 438'-9" 16.0' RCIC (X-33) 452'-0" 3.4'

The minimum depth at which vortex formation at the suction in lets will be prevented is:

Flow Rate (max)

Velocity Submergence

RHR 8000 gpm 5.674 fps 2.41' LPCS 7800 gpm 5.533 fps 2.35'

HPCS 7175 gpm 5.089 fps 2.16' RCIC 600 gpm 3.295 fps 0.84'

The RCIC pump suction will have 2.5 ft of submergence. The inlet to each of the ECCS lines is at least 5 ft deeper than require d to preclude vortexing, and theref ore, vortex formation is not considered a problem.

See also the response to Question 211.062 for further information.

ISSUE: RSB-11 ASS U RAN C E OF FILLED ECCS LINE (6.3.2) Question:

Instrumentation is not sufficiently sensitive to detect voids at th e top of ECCS pipe lines. The applicant must provide adequate instrument ation to assure filled ECCS lines.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-6 Response: Filled ECCS lines are assured by:

a. Jockey pump system on same di vision as system being filled, b. Pressure switch on pump discharge with control room annunciation, c. Technical Specification surveillance -

upon high point vents to check for air.

See also the response to Question 211.079 for additional information.

ISSUE: RSB-12 OPERABILITY OF ADS

Question:

Show that the air supply to the ADS is sufficien t for the extended opera ting time required and is assured by reliability data that th e ADS will function as required.

Response:

Safety-related backup to the CI A system is provided by re dundant, independent nitrogen gas bottle banks. Upon loss of CIA, the system will be automatically is olated as the backup nitrogen supply is automatically fed into the sy stem. The nitrogen bottle supply is sized for a 30-day supply to the seven ADS valves. The nitrogen supply can fart her be backed up by a portable auxiliary nitrogen supply (if necessary) which can be connected outside the reactor building. Please refer to Section 9.3.1.2.2 and the responses to Questions 031.121 and 211.048.

ISSUE: RSB-13 LEAKAGE RATE TESTING OF VALVES USED TO ISOLATE REACTOR COOLANT SYSTEM

(5.3.2)

DELETED ISSUE: RSB-14 OPERABILITY OF ECCS PUMPS

(6.3.2)

Question:

The applicant must provide assurance that th e ECCS pumps can func tion for an extended time (maintenance free) under the most limiting post-LOCA conditions.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-7 Response:

This issue has been closed on Zimmer, Shoreham, and LaSalle dockets on the basis of information presented in response to NRC questions. Similar info rmation has been provided on the rest of the dockets. The response to CGS Question 211.072 has been r evised to include the latest information available.

NUREG-0737 Task II.B.2 is related to the issue discussed above and is addressed in Appendix B of the FSAR. The shielding evaluation referred to in Appendix B will show that the ECCS pumps will operate for the accident duration (assumed to be six months), using the source terms from II.B.2.

ISSUE: RSB-15 ADDITIONAL LOCA BREAK SPECTRUM (6.3)

Question:

The staff does not concur that the Zimmer LOCA analysis is an appropriate break spectrum for CGS because of: 1) higher power level in CGS, 2) different fuel assemb ly design in CGS, and

3) higher PCTs predicted for CGS.

The staff requires that the applicant provide th e following LOCA analyses to complete the break spectrum:

a. One additional recircula tion line break with a C D coefficient 0.6 times the DBA, using the large break model analysis.

b. One additional recirculation line break (0.02 ft

2) using the small break model analysis.

Response:

This issue has been closed on the LaSalle docket on the basis of information presented in response to NRC questions. Sim ilar information has been provid ed in the revised response to CGS FSAR Question 211.068.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-8 ISSUE: RSB-16 LOCA ANALYSIS (6.3.4)

Question:

You have analyzed the effect on the DBA-LOCA of instantaneous closure of the flow control valve (FCV) in the unbroken loops. This overly conservative result indi cated an increase in peak clad temperature (PCT) of 300F which, if added to the DBA-L0CA PCT, would be in excess of the maximum PCT criterion of 10 CFR 50.46.

Response:

The response to this issue was provided in Amendment No. 11 as a response to Question 211.083. The respons e to this question is summa rized and expanded upon below.

FCV closure in the unbroken loop is not expected to occur during the LOCA event. However, even if the FCV were signaled to close for some unlikely reason (LOCA plus two failures:

failure of drywell high pressure signal such that FCV lockup does not occur, and failure of FCV controls), backup electronic velocity-limiter s are included in the recirculation control system to limit FCV velocity to 10 +/- 1% actuator stroke rate. Additional multiple specific component failures in these limiter s must occur to cause full closure of the FCV at velocities in excess of this value. The co mbined probability of occurrence of these specific failure modes during LOCA is less than 10

-6 per year. Accordingly, the electronically limited rate of 10 +/- 1% of FCV actuator stroke/rate is considered a realistic yet conservative closure rate.

Using approved standard licensing m odels, ECCS analyses were performed to determine the effect (sensitivity) on peak cl adding temperature from FCV closur e at the 11% per second rate.

The calculated maximum peak temperature increase was 45°F for CGS. This contrasts markedly with the approximate 300°F rise in cladding temperature associated with an arbitrary assumption of instant closure of the FCV, as was cited on another BWR/5 docket.

Thus, the peak cladding temperature effect is concluded to be very small. The probability of FCV fast closure simultaneously with a LOCA is extremely remote. Accordingly, fast FCV closure in conjunction with the DBA-LOCA is not expected to o ccur and need not be compared to the maximum PCT criterion of 10 CFR 50.46.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-9 ISSUE: RSB-17 OPERATOR ACTION, ANALYSIS OF CRACK IN THE RHR LINE (6.3.4) Question:

Provide the following inform ation related to pipe breaks or leaks in high or moderate energy lines outside containment associated with the RHR system when the plant is in a shutdown cooling mode.

a. Provide the discharge rate from pipe breaks for the systems outside containment used to maintain core cooling. This valve should be consistent with the requirements of SRP 3.6.1 and BTP APCSB 3-1.

b. Determine the time frame available fo r recovery based on these discharge rates and their effect on core cooling.

c. Describe the alarms available to alert the operator to the event, the recovery procedures to be utilized by the opera tor, and the time available for operator action.

A single failure criterion consistent with SRP 3.6.1 and BTP ABCSB 3-1 should be applied in the evaluation of the recovery procedures utilized.

Response: a. The RHR system is a low pressure sy stem, and all of the piping outside of the primary coolant pressure boundary is cl assified as "moderate energy" piping and, according to the NRC standards cited, only cracks (i.e., not breaks) are

considered in moderate energy piping.

Reactor vessel pressure must be decreased to below 135 psig before the RHR system can be connected to the reactor vessel. The larges t suction pipe is 24 in. Sc hedule 40 pipe. A crack in this pipe corresponding to the maximum crack size would produce a flow rate of

1443 gpm, with no allowance for flow re duction due to two-phase flow. This is the maximum possible in any RHR system pipe. A crack of this magnitude would be detected by the leak detection system or area radiation detectors and sump alarms. Isolation of the reactor would occur by operator action, or automatically from the leak detection system or from th e reactor protection system on Level 3 reactor water level.

b. If a break should occur in one RHR shutdown cooling loop outside the containment during shutdown, the followi ng action is taken upon detection and isolation. The main steam isolation valves will be reopened and reactor excess C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-10 steam will blow down to the main conde nser until the shutdown cooling process via the other RHR loop is establis hed. Time: less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

The redundant shutdown cooling loop comp onents are also not assumed to fail under the cited NRC requirements of BTP APCSB 3-1.

If the pipe crack should occur in the common manifold supplying both redundant loops, the isolation mechanism is the same as before, but recovery would require reversion to the alternate shutdown configuration discussed in Section 15.2.9. In this configuration, vessel water is circulated from the suppression pool to the RHR heat exchanger to the vessel with return to the suppression pool via the ADS discharge lines. Time: less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

If the pipe crack should occur in the RHR service water piping, sump alarms would result in operator isolation of that loop and establishm ent of cooling in the redundant shutdown loop.

Time: less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

In evaluating the above analysis, the followi ng is also offered. If the main condenser vacuum has been lost and the MSIVs are already cl osed prior to the crack occurrence, reestablishment of condenser vacuum, MSIV reopening, vessel inventory control, and restart of steam dump to the main condenser is possible in about 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Vessel in ventory can be cont rolled by overflow through the reactor water cleanup system if too high, and by use of feedwater pumps or HPCS/LPCS/LPCI if too low. Ve ssel pressure is controlled by manual operation of safety/relief valves on MSIV closure as required.

c. The alarms available have been descri bed in the response to part (a) and part (b) of this question. The recovery pro cedures to be utilized by the operator, and the time available for operator action are provided below.

A special analysis was made by a hypot hesized crack in the BWR suction line outside of primary containment during operation in th e shutdown cooling mode.

This analysis was performed with the standard GE LOCA models. For this event, the realistic or actual system conditions are as follows:

No high pressure systems are available for water inventory restoration, i.e., no feedwater, no HPCS, and no RCIC, but the reactor water level is at normal elevation at the start of this event. Vessel pressure is less than 150 psia and the MSIVs are closed at the start of this event. The deca y heat is approximately 1% of rated power, i.e., appr oximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> have elapsed subsequent to reacto r scram or shutdown.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-11 For a conservative solution to this hypothetical event, the following sequence of events and conditions were assumed to exist or ensue from the hypothesize d crack in the suction line:

a. Crack occurs in the RHR lines water; level decreases to reactor vessel Level 3; then RHR isolation commences and is completed 40 seconds later.

b. System pressure rises as a result of the isolation to where the vessel pressure reaches the SRV setpoint, t hus causing them to open, blow down, and reclose.

c. Inventory depletion results from bl owdown and from leak age out of these cracked lines.

d. The operator manually actuates ADS to reduce vessel pressure to where the low pressure ECCS can replenish the water inventory.

e. Water level is restored to within normal limits to protect the core from over temperature.

Results are presented in Figures I.8-1 through I.8-4 for a bounding calculation of this event. The standard Appendix K assumptions were used along with these conservative initial conditions.

a. The timing index was started at the RHR isolation (when Level 3 was attained) to neglect the time fo r the level to fall from normal water level to Level 3 (about 2 minutes).

b. An initial pressure of 1055 psia was assumed to neglect the pressure rise time from the 150 psia (pressure permissive for shutdown cooling) upon completion of the RHR isolation to the 1055 pressure attainment. This results in increased mass loss during the 40-second isolation peri od due to greater driving pressure. It also decreases the time increment needed for pressure to attain the relief valve setpoint.

c. The analysis assumes that scram occurs coincident w ith the start of the timing instead of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> earlier. This assumption maximize s the peak clad temperature and steam producti on during the transient t hus driving more fluid from the vessel and prolonging the blowdown phase.

d. Only one LPCS and one LP CI loop were assumed to be available throughout the event. Operator action does not include possible diversion of the other two LPCI loops from the RHR mode.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-12 e. The crack area used in the analysis is defined consistently with the MEB 3-1 guidance for crack size. This crack area is consiste nt with FSAR postulates.

Results from this conservative analysis show that more than 20 minutes are available for the operator to depressurize the vessel. Once the system pressure is below the LPCI or LPCS shutoff head, the reactor water le vel is restored to normal limits very rapidly. The maximum clad temperature is much less t han the arbitrary 2200°F limitation.

ISSUE: RSB-18 LOCA ANALYSIS - DIVERSION OF LOW PRESSURE COOLANT INJECTION SYSTEM (6.3.4) Question:

The issue is... "If low pressure coolant injecti on diversion prior to ten minutes is allowed by design, then procedural rest rictions alone are not sufficient unless analyses are submitted which show compliance with 10 CFR 5O.46 for diversion earlier than ten minutes."

Response:

Analyses of BWR performance following a small break LOCA and LOCA mitigation under degraded conditions have been pe rformed by General Electric as a part of the BWR Owners' Group program. Analyses bases, assumptions, and conclusions are discussed in GE report NEDO-24708A, Revision 1, December 1980, entitle d, "Additional Information Required for NRC Staff Generic Report on Boiling Water Reacto rs." Reference is made to 3.1.1 (Small Break LOCA) and 3.5.2 (Inade quate Core Cooling). It should be noted that these analyses were performed utilizing "realisti c" assumptions as defined in 3.1.1.2 and 3.

5.2.4. The conclusion, 3.5.2.1.8, summarizes the capability of the BWR to maintain adequate core cooling, even under severely degraded conditions resulting from multiple failures and operator errors, following a loss of inventory either through a pipe break or through the safety relief/valve.

Based on the first group of analyses presented, it was concluded that for any plant and any loss of inventory event, the ability of ADS and one low pressure ECC system provides adequate core cooling if no high pressure injecti on is available. These analyses covered the case of multiple mechanical or electrical failure s and operator errors that might have caused the failure of the system, assumed to be unavailable.

The second set of analyses addresse d the condition of the vessel be ing at high pressure with a low water level. It was shown t hat operator actions either to in itiate high pressure systems or to depressurize the vessel and initiate at least one low pressure system, terminate this condition C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-13 and assure adequate core c ooling. The analyses showed that even for such severely degraded transients, there is sufficient time for operator action to mitigate the consequences.

The third set of analyses addressed the condition of the vessel being at low pressure with a low water level but with the low pressure systems not injecting.

It was shown that operator actions either to start the low pressure systems injecting into the vessel or to initiate the high pressure systems, terminate this condition and assure adequate core cooling.

For all analyses, it was shown that the process variable information available to the operator in the control room is sufficient to adequately warn of an inventory threatening event and to present the information the opera tor needs to assure that appr opriate actions are taken to maintain adequate core cooling. The control room indications will not mislead the operator when taking corrective actions. Even under the extremely degraded conditions considered in these analyses, the BWR require s only the most basic operator actions to mitigate the consequences of an inventory threatening event.

If the operator were to divert LPCI prior to ten minutes post-LOCA, such an action would be considered an operator error. Since the current ECCS pe rformance evaluation already assumes the accident, a loss of offsite power and a worst active single failure, an additional operator error is considered to be an additional Appendix K a ssumption. It is therefore appropriate that the "realistic" assumption analyses be considered for this situation as stated in the conclusion in NEDO-24708A "for any plant and any lo ss of inventory event, the adequate availability of ADS a nd one low pressure ECC syst em provides adequate core cooling..."

This analysis is deemed acceptable to provid e satisfactory assuran ce of acceptable event consequences, in consideration of the equipment failures and operator errors assumed.

To resolve the concern of the NRC staff that premature divers ion of low pre ssure coolant injection (LPCI) flow to containm ent sprays could adversely e ffect core cooling, the CGS symptom based emergency procedures will be carefully construc ted to caution the operator against such diversion unless "adequate core cooling is assured." Thes e procedures, which were developed with the assi stance of the BWR Owners' Gr oup and reviewed and accepted by the NRC staff, clearly identify LPCI diversion as secondary to the core cooling requirements except in those instances, outside the plant de sign envelope, which invo lve multiple failures and for which maintenance of containment integrity is required to minimize risk to the environment.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-14 ISSUE: RSB-19 FAILURE OF FEEDWATER HEATER (15.1) Question:

The applicant's analysis for the fa ilure of the feedwater heater indicates that the temperature drop is no greater than 100°F. At a domestic boiling water reactor an actual feedwater temperature occurred which dem onstrated a temperature differ ence of 150°F. The applicant must justify the decrease in temperature drop used for this e vent or recalculate the transient by using a justified temperature de crease to assure conform ance with applicable criteria.

Response:

Refer to revised respons e to Question 211.087.

ISSUE: RSB-20 USE OF NONRELIABLE EQUIPMENT IN ANTICIPATED OPERATIONAL TRANSIENTS (15.1)

Question:

In analyzing anticipated operational transients, the applicant t ook credit for equipment which has not been shown to be reliabl

e. Our position is that this equipment be identified in the technical specifications with re gard to availability, setpoints, and surveillance testing. The applicant must submit its plan for implementing this requirement along with any system modification that may be required to fulfill the requirement.

Response:

The response to the above stated concern is provided in response to Questions 211.085, 211.086, and 211.155.

ISSUE: RSB-21 USE OF NON-SAFETY GRADE EQUIPMENT IN SHAFT SEIZURE ACCIDENT (15.3)

Question:

The applicant included the use of non-safety grade equipment in his analysis for shaft seizure and shaft break accidents. We require that these accidents be reanalyzed without allowance for the use of non-safe ty grade equipment.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-15 Response:

The response to the above stated concern is provided in the revised response to Question 211.092. Questions 211.185 and 211.211 also re ference this concern.

ISSUE: RSB-22 ATWS

(15.2.1)

Question:

We require that the applicant agrees to implement plant modifications on a scheduled basis in conformance with the Commission's final resolution of ATWS. In the even t that LaSalle starts operation before necessary plant modifications are implemen ted, we require some interim actions be taken by LaSalle in order to further reduce the risk from ATWS events. The applicant will be required to:

a. Develop emergency procedures to train operators to recognize an ATWS event, including consideration of scram indicators, rod position indicators, flux

monitors, vessel level and pr essure indicators, relief valve and isolation valve indicators, and containment temperature, pressure, and radiation indicators.

b. Train operators to take action in the event of an ATWS including consideration of immediately manual scramming the re actor by using the manual scram buttons followed by chan ging rod scram switches to the scram position, stripping the feeder breakers on the reacto r protection system power distribution buses, opening the scram discharge volume drain valve, prompt actuation of the standby liquid control system, and prompt placement of the RHR in the pool cooling mode to reduce the severity of the containment conditions.

Response:

See 1.5.1.1.2 for a discussion of CGS modifications which addresses compliance to the final ATWS rule. The required procedure developm ent and operator traini ng were accomplished prior to fuel load.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-16 ISSUE: RSB-23 PEACH BOTTO M TURBINE TRIP TESTS (4.4.1 , 4.4.2) Question:

These tests have been evaluated and assessed using the ODYN computer code.

Response: The NRC has completed their review of the ODYN Code. See the Safety Evaluation Report letter of November 4, 1980.

Also, see Chapters 4 and 15. The appropriate sections of these chapters ha ve been revised utilizing results of re-analysis of required transient s using the ODYN Code. See the revised response to Qu estion 211.049.

Refer also to RSB-4.

ISSUE: RSB-24 MCPR

(4.4.1 , 4.4.2 , 15.1)

Question:

After completion of over-pre ssure analysis, the minimum cr itical power ratio must be recalculated taking into consideration the turbine trip without bypass event.

The transient of generator l oad rejection without bypass results in an MCPR equal to 1.02 which is below the safety limit of 1.06. Th e applicant classified this event an infrequent occurrence which would allo w some fuel damage. We do not c oncur with this classification for this event, and we require that the operati ng limit be modified to satisfy the MCPR limit of 1.06.

Response: The response to the above stated concern is prov ided in revised respons e to Question 211.084.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-17 ISSUE: RSB-25 GEXL CORRELATION

Question:

Although we conclude that the GEXL correlation is acceptable for initial core load, we are concerned that GEXL correlation may not be conservative fo r reload operation.

Response: Columbia Generating Station will use the app licable correlation to pr edict the onset of transition boiling for all reloads.

ISSUE: RSB-26 STABILITY EVALUATION

Question:

Please refer to NRC Questi on 221.009 for this question.

Response:

Please refer to the response to NRC Question 221.009.

ISSUE: RSB-27 SCRAM DISCHARGE VOLUME

Question:

The applicant should assess, reeval uate, and possibly modify the present scram system in light of the incident at Browns Ferry 3, where a m anual scram failed to insert all control rods.

Response:

The CGS scram discharge volume (SDV) design has been evaluated against the NRC generic study "BWR Scram Discharge Syst em Safety Evaluation" of Decembe r 1, 1980. The results of this evaluation indicated that the current CGS scram discharge system design was acceptable

with implementation of some minor modifications. A summary of the evaluation results and the required modifications are provided below.

a. Hydraulic Coupling - The current SDV design provides two separate scram discharge volume headers, wi th an integral instrumented volume (IV) at the end of each header. This design configur ation ensures a dir ect hydraulic couple between the SDVs and IVs.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 I.8-18 b. Instrumentation - The existi ng level sensors (six total) are all of one design, i.e., float type (magnetrol) level switches.

To meet the specified requirements, six additional diverse le vel sensors will be added to provide full redundancy for level monitoring and scram initiation. In addition, all level instrumentation will be relocated and repiped dir ectly to the IVs rather than being connected to the vent and drain lines.

c. Vent and Drain Lines - The CGS desi gn incorporates an in dependent vent and drain system for the SDV. The scram discharge headers are presently vented directly to the reactor build ing atmosphere and the system drain is piped directly from the bottom of the IVs to the building's radioactive drai n system. A second vent valve and drain valve will be adde d to provide redundant SDV isolation during a reactor scram.

d. Surveillance Testing - Additional su rveillance test procedures will be implemented to ensure operability of the level instruments, vent and drain isolation valves, as well as the overall system.

Please refer to respons e to Question 010.041.

ISSUE: RSB-28 SRV SURVEILLANCE

Question:

A safety/relief valve surveill ance program should be developed to record operating and maintenance experience to facilitate identification of generi c safety/relief valve problems.

Response:

CGS will develop a surveillance program for safety/relief valves similar to that being developed by the BWR Owners' Group submitted to the NRC by letter GO2-81-563, G. D. Bouchey to A. Schwencer, "LRG Appendix I,"

dated December 30, 1981.

The CGS safety/relief valve surveillance program will be available for onsite review.

Vessel Pressure Versus Time for a Crack in the RHR Line 970187.15 I.8-1 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.1.2 0.8 0.4 0.4 0.8 1.2 1.6Time (Sec) x 10 3 Vessel Pressure (PSIA) x 10 3SRV's ActuatedADS ActuatedVessel PressureDuring Shutdown Cooling (1LPCI + 1LPCS + ADS)

Columbia Generating StationFinal Safety Analysis Report Water Level Versus Time for a Crack in the RHR Line 970187.16 I.8-2 Figure Amendment 53November 1998 Form No. 960690Draw. No.Rev.40 20 0.4 0.8 1.2 1.6Time (Sec) x 10 3During Shutdown Cooling (1LPCI + 1LPCS + ADS)Water Level Inside ShroudTop of Active Fuel Bottom of Active FuelADS Actuated Water Level (Ft)

Low-Pressure System Injection 0 Columbia Generating StationFinal Safety Analysis Report Peak Cladding Temperature Versus Time for a Crack in the RHR Line 970187.17 I.8-3 Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.2 1 0.4 0.8 1.2 1.6 Time (Sec) x 10 3 During Shutdown Cooling (1LPCI + 1LPCS + ADS)

Peak Cladding Temperature Peak Cladding Temperature (°F) x 10 3 PCT Limit (2200 F)0 Columbia Generating Station Final Safety Analysis Report HTC at PCT Node Versus Time for a Crack in the RHR Line 970187.18 I.8-4 Figure Amendment 53 November 1998 Form No. 960690 Draw. No.Rev.1 0.4 0.8 1.2 1.6 Time (Sec) x 10 3 Heat transfer Coefficient (BTU/Hr-Ft 2-°F) During Shutdown Cooling (1LPCI + 1LPCS + ADS) 10 100 1000 10,000 100,000 Convective HTC Columbia Generating Station Final Safety Analysis Report