ML14010A315

Final Safety Analysis Report, Amendment 62, Appendix B - Response to Regulatory Issues Resulting from TMI-2

ML14010A315
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: ML14010A315 (79)

Text

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 Appendix B RESPO N SE TO RE G ULATORY ISSUES RESULTI NG FROM TMI-2

TABLE OF CONTENTS Section Page LDCN-00-018,01-009, 01-00A B-i I.A.1.2 Shift Supervisor Responsibilities..................................................B.1-1 I.C.1 GUIDANCE FOR THE EVALUATION AND DEVELOPMENT OF PROCEDURES FOR TRANSIENTS AND ACCIDENTS

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

B.1-5 I.C.2 SHIFT AND RELIEF TURNOVER PROCEDURES...........................B.1-8 I.C.4 CONTROL R OOM ACCESS........................................................B.1-10 I.C.6 GUIDANCE ON PROCE DURES FOR VERIFYING CORRECT PERFORMANCE OF OPERATING ACTIVITIES.............................B.1-11 I.C.7 NSSS VENDOR REVIEW OF PROCEDURES.....................................B.

1-14 I.C.8 PILOT MONITORING OF SELECTED EMERGENCY PROCEDURES FOR NEAR-TERM OPERATING LI CENSE APPLICANTS......................B.1-14 I.D.1 CONTROL ROOM DESIGN REVIEWS.............................................B.1-15 I.G.1 PREOPERATIONAL AND LOW-POWER TESTING.............................B.1-18 II.B.1 REACTOR COOLANT SYSTEM VENTS.......................................B.2-1 II.B.3 POSTACCIDENT SA MPLING CAPABILITY......................................

B.2-9 II.F.1.3 Containment High-Range Radiation Monitor...................................B.2-16 II.F.1.4 Containment Pressure Monitor....................................................B.2-21 II.F.1.5 Containment Wa ter Level Monitor Position.....................................B.2-22 II.F.1.6 Containment Hydrogen Monitor...................................................B.2-23 II.F.2 INSTRUMENTATION FOR DETECTION OF INADEQUATE CORE COOLING......................................................................B.2-24 II.K.1.5 Assurance of Proper Engineered Safety Feature Functioning...............B.2-25 II.K.1.22 Proper Functioning of Heat Removal Systems................................B.2-26 II.K.1.23 Reactor Vessel Level Instrumentation..........................................B.2-30 II.K.3.21 Restart of Core Spray and Low Pressure Coolant Injection Systems.....B.2-32 II.K.3.25 Effect of Loss of Alter nating-Current Power on Pump Seals...............B.2-33 II.K.3.44 Adequate Core Cooling for Transients with a Single Failure..............B.2-34 II.K.3.45 Evaluation of Depressu rization with Other than Automatic Depressurization System..........................................................B.2-43 II.K.3.46 Response to List of Concerns from ACRS Consultant (Michelson Concerns).............................................................B.2-53 III.D.1.1 Primary Coolant Sour ces Outside Containment ..............................B.3-1 III.D.3.3 Improved Inplant Iodine Instrumentation Under Accident Conditions....B.3-3

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 Appendix B RESPONSE TO REGULATORY ISSUES RESULTING FROM TMI-2

LIST OF TABLES

Number Title Page B-ii I.A.1.2-1 Shift Supervisor Re sponsibilities (2.2.1.A)...............................B.1-3 II.F.1-3 Containment High-Range Radiation Monitor.............................

B.2-19 II.K.3.44-1 Summary of In itiating Transients............................................

B.2-39 II.K.3.44-2 List of Single Failures Which Can Potentially Degrade the Course of a BW R Transient..................................................B.2-40

II.K.3.44-3 Worst Case of Transient with a Single Failure for Different BWR Product Lines............................................................

B.2-41 II.K.3.44-4 Participating Utilities - NUREG-0737......................................B.2-42

II.K.3.45-1 Results for BWR/6 Outs ide Steam Line Break No High Pressure Systems Available...................................................B.2-47

II.K.3.45-2 Results for BWR/6 Stuck-Open Relief Valve No High Pressure Systems Available...................................................B.2-48

II.K.3.45-3 Results for BWR/3 Outs ide Steam Line Break No High Pressure Systems Available...................................................B.2-49

II.K.3.45-4 Results for BWR/3 Outsid e Steam Line Break on Appendix K Assumptions with No High Pressure Systems.............................B.2-50

II.K.3.45-5 Participating Utilities - NUREG-0737......................................B.2-51

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 Appendix B RESPO N SE TO RE G ULATORY ISSUES RESULTI NG FROM TMI-2

LIST OF FIGURES

Number Title B-i i i II.K.3.45-1 Vessel Blowdown Rates Used in Analysis C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.1-1 I.A.1.2 Shift Supervisor Responsibilities

Position (NUREG-0578, 2.2.1.A)

a. The highest level of co rporate management of each licensee shall issue and periodically reissue a ma nagement directive that emphasizes the primary management responsibility of the shift s upervisor for safe operation of the plant under all conditions on his shift and that clearly esta blishes his command duties.

b. Plant procedures shall be reviewed to ensure that the duties, responsibilities, and authority of the shift supe rvisor and control room ope rators are properly defined to effect the establishment of a definite line of command and clear delineation of the command decision authority of the shift supervisor in the control room relative to other plant ma nagement personnel. Par ticular emphasis shall be placed on the following:

1. The responsibility and authority of the shift supervisor shall be to maintain the broadest perspective of operational conditi ons affecting the safety of the plant as a matter of highest prior ity at all times when on duty in the control room. The idea shall be reinforced that the shift supervisor should not be come totally involved in any single operation in times of emergency when multiple ope rations are required in the control room.

2. The shift supervisor, until properly relieved, shall remain in the control room at all times during accident situations to direct the activities of control room operators. Persons authorized to relieve the shift supervisor shall be specified.

3. If the shift supervisor is temporarily absent from the control room during routine operations, a lead control room operator shall be designated to assume the control room command f unction. These temporary duties, responsibilities, and authority shall be clearly specified.

c. Training programs for shift supervisors shall emphasize and reinforce the responsibility for safe operation and th e management function of the shift supervisor is to provide for ensuring safety.

d. The administrative duties of the shift s upervisor shall be reviewed by the senior officer of each utility responsible for pl ant operations. Admi nistrative functions that detract from or are subordinate to the management responsibility for C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.1-2 ensuring the safe operation of the plant shall be delegated to other operations personnel not on duty in the control room.

Clarification

The table attached provides clarification to the above position.

Columbia Generating Station Position The administrative duties of the shift manager have been reviewed; inappropriate functions were delegated to other pers onnel including the shift support s upervisor. The shift support supervisor will assist the shift manager by directing pe rsonnel assigned to perform balance-of-plant operating f unctions and by perf orming shift administrative duties.

Procedures have been reviewed to ensure that the shift manager, control room supervisor, shift support supervisor, and operator fu nctions are defined adequately to establish th e shift manager as the commanding authority for plant operations relative to other plant management. The shift manager is to ensure the safe operation of the plant under all conditions. During an emergency, the responsibility for directing and controlling the acti ons of the operating crew to place and maintain the plant in a safe condition rests with the shift mana ger. During accident conditions, the shift manager will normally be in the control room at all times until properly relieved. He may elect to direct recovery activities at the scene of the accident.

This principle has been reinforced by manageme nt directive that empha sizes that the shift manager's primary responsibility is the safe operation of the plant under all conditions.

The shift manager's administrative duties will be reviewed annually by the crew operations manager to ensure that administrative responsibilities do not interfere with the primary responsibility.

Appropriate documentation will be available onsite for revi ew by the Nuclear Regulatory Commission (NRC) I&E Branch.

This position has been accepted in the NRC Staff Safety Evaluation Report NUREG-0892 dated March 1982, section 13.5.1.8.

C OLUMBIA G ENERATING S TATION Amendment 57 F INAL S AFETY A NALYSIS R EPORT December 2003 LDC N-0 2-0 6 9 B.1-3 Table I.A.1.2-1 Shift Supervisor R e sponsibilities (2.2.1.A)

NUREG-0578 Position (Positi on Number)

Clar i f ication Highest Level of Corporate Management (1.) Vice President, Nuclear Generation Periodically Reissue (1.)

Annual Reinforcement of Company Policy Management Direction (1.)

Formal Documentation of Shift Personnel, All Plant Management , Copy to IE Region Properly Defined (2.0)

Defined in Writing in a Plant Procedure Until Properly Relieved (2.B)

Formal Tr ansfer of Authority, Valid SRO License, Recorded in Plant Log Temporarily Absent (2.C) Any Absence Control Room Defined (2.C)

Includes Shift Manager Office Adjacent to the Control Room Designated (2.C)

In Admi nistrative Procedures Clearly Specified Defined in Administrative Procedures SRO Training Specified in ANS 3.1 (Draft) Section 5.2.1.8 Administrative Duties (4.)

No t Affecting Plant Safety Administrative Duties Reviewed (4.) On Same Interval as Reinforcement: i.e., Annual by Vice Pres ident, Nuclear Generation

This requirement was met before fuel loadi ng. See NUREG-0578, Sec tion 22.1a, Item 4 and NRC letters of September 27 and November 9, 1979

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 B.1-5 The italicized information is historical and was provided to support the application for an operating license.

I.C.1 GUIDANCE FOR THE EVALUATION AND DEVELOPMENT OF PROCEDURES FOR TRANSIENTS AND ACCIDENTS

Position (NUREG-0737)

In the letters of September 13 and 27, October 10 and 30, and November 9, 1979, the Office of Nuclear Reactor Regulation re quired licensees of operating plants, applicants for operating licenses and licensees of plants under construc tion to perform analys es of transients and accidents, prepare emergency procedure guidelines, upgrade emer gency procedures, including procedures for operating with natural circulation conditions, and to conduct operator

retraining (see also Item I.A.2.1). Emergency pr ocedures are required to be consistent with the actions necessary to cope with the transients and accide nts analyzed. Analyses of transients and accidents were to be completed in early 1980 and implementation of procedures and retraining were to be completed 3 months after emergen cy procedure guidelines were established; however, some difficulty in completing these requirements has been experienced.

Clarification of the scope of th e task and appropriate schedule re visions are being developed.

In the course of review of these matters on Babcock and Wilc ox (B&W) designed plants, the staff will follow up on the bulletin and orders matters relating to analys is methods and results, as listed in NUREG-0660, Appendix C (see Table C.1, Items 3, 4, 16, 18, 24, 25, 26, 27; Table C.2, Items 4, 12, 17, 18, 19, 20; and Table C.3, Item s 6, 35, 37, 38, 39, 41, 47, 55, 57).

Changes to Previous Requirements and Guidance:

a. Modification to Clarification

1. Addresses owners' gr oup and vendor submittals.

2. References to ta sk action plan Items I.C.8 and I.C.9.

3. Scope of procedures review is explained.

4. Establishes confi guration control of guidelines for emergency procedures.

b. Modification to Implementation

1. Deleted reference to NUREG-0578, Recommendation 2.1.9 for Item I.C.1(a)2 , inadequate core cooling.

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 B.1-6 The complete NRC position description and cl arification is contai ned in NUREG-0737 -

Task I.C.1.

This requirement is to be completed by fuel load.

Clarification

None.

Columbia Generating Station Position Columbia Generating Station (CGS) has participated, and continue s to participate, in the BWR Owner's Group program to develop Emergency Procedure Guidelines for General Electric Boiling Water Reactor. Following are a brief description of the submittals to date, and a

justification of their adequacy to support guidelines development.

a. Description of Submittals

1. NEDO-24708, "Additional Information Required for NRC Staff Generic Report on Boiling Water Reactors,"

August 1979; including additional sections submitted in prepublic ation form since August 1979.

(a) Section 3.1.1 (Small Break LOCA).

Description and analysis of sma ll break loss-of-coolant events, considering a range of break si zes, location, and conditions, including equipment failures and oper ator errors; description and justification of analysis methods.

(b) Section 3.2.1 (Loss of Feedwate r) - revised and resubmitted in prepublication from March 31, 1980.

Description and analysis of loss of feedwater events, including cases involving stuck-open relief valves, and including equipment failures and operator errors; desc ription and justification of analysis methods.

(c) Section 3.2.2 (Other Opera tional Transients) - submitted in prepublication form March 31, 1980; revised and resubmitted in prepublication form August 22, 1980.

Description and analysis of each FSAR Chapter 15 event resulting in a reactor system transient; demonstration of applicability of 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 B.1-7 analyses of 3.1.1, 3.2.1, and 3.5.2.1 to each event; demonstration of applicability of Emergency Procedure Guidelines to each event.

(d) Section 3.3 (BWR Natural and Forced Circulation).

Description of natural and forced circulation cooling; factors influencing natural circulati on, including no ncondensables; re-establishment of forced ci rculation under transient and accident conditions.

(e) Section 3.5.2.1 (Analyses to Demonstrate Adequate Core Cooling) - submitted in prepublication form November 30, 1979; revised and resubmitted in prepublication form September 16, 1980.

Description and analysis of lo ss-of-coolant events, loss of feedwater events, and stuck-open re lief valves events, including severe multiple equipment failures and operator errors which, if not mitigated, could result in conditions of inadequate core cooling.

(f) Section 3.5.2.3 (Diverse Methods of Detecting Adequate Core Cooling) - submitted in prepub lication form December 28, 1979.

Description of indications avail able to the BWR operator for the detection of adequate co re cooling (detailed instrument responses are described in 3.1.1, 3.2.1, and 3.5.2.1).

(g) Section 3.5.2.4 (Justification of Analysis Methods) - submitted in pre-publication form September 16, 1980.

Description and justification of analysis methods for extremely degraded cases trea ted in 3.5.2.1.

2. BWR Emergency Procedure Guidelines (Revision 3).

Guidelines for BWR Emergency Pr ocedures based on identification and response to plant symptoms; includi ng a range of equipment failures and operator errors; including severe multiple equipment failures and operator errors which, if not mitigat ed, would result in conditions of inadequate core cooling; including conditions when core cooling status is uncertain or unknown.

C OLUMBIA G ENERATING S TATION Amendment 54 F INAL S AFETY A NALYSIS R EPORT April 2000 B.1-8 3. NEDO-24708A, Revision 1, December 1980.

b. Adequacy of Submittals:

The submittals described in (a) abo ve have been discussed and reviewed extensively among the BWR Owner's Gr oup, the General Electric Company, and the NRC staff. The NRC staff has found (NUREG-0737 p. I.C.1-3) that "the analysis and guidelines subm itted by General Electric Company (GE) Owners' Group...comply with the requirements (of the NUREG-0737 clarification)." In Reference 1, the Director of the Division of Licensing states, "we find the Emergency Procedure Guide lines acceptable for tria l implementation (on six LRG-1 plants with applications for operating licenses pending)."

CGS believes that in view of these findi ngs, no further detail ed justification of the analysis or guidelines is necessary at this time.

Reference 1 further states, "(during the c ourse of implementation we may identify areas that require modification or further analysis and justification." The enclosure of Reference 1 identifies several such areas. CGS will work with the BWR Owners' Group in re sponding to such requests.

By our commitment to work with the Owners' Group on such requests, on schedules mutually agreed to by the NRC and the Owners' Group, and by reference to the BWR Owners' Group analyses and guidelines already submitted, our response to th e NUREG-0737 requirement "for reanalysis of transients and accidents and inadequate core cooling and pr eparation of guidelines for development of emergency procedures" is complete.

This position has been accep ted in the NRC Safety Evaluation Report NUREG-0892, Supplement 5 dated April 1984, section 13.5.2.2.

References

1. Letter, D. G. Eisenhut (NRC) to S. T. Rogers (BWR Owners' Group), regarding Emergency Procedure Guide lines, October 21, 1980.

I.C.2 SHIFT AND RELIEF TURNOVER PROCEDURES

Position The licensees shall review and revise as nece ssary the plant procedur e for shift and relief turnover to ensu re the following:

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.1-9 a. A checklist shall be provided for the oncoming and offgoing control room operators and the oncoming shift supervisors to complete and sign. The following items, as a minimum, sha ll be included in the checklist.

1. Assurance that critical plant para meters are within allowable limits (parameters and allowable limits shall be listed on the checklist).

2. Assurance of the availability a nd proper alignment of all systems essential to the prevention and mitigation of operationa l transients and accidents by a check of the control console (what to check and criteria for acceptable status shall be included in the checklist).

3. Identification of systems and components that are in a degraded mode of operation permitted by the Technical Specifications. For such systems and components, the length of time in the degraded mode shall be compared with the Technical Specifications action statement (this shall be recorded as a separate entry on the checklist).

b. Checklists or logs shall be provided for completion by the offgoing and ongoing auxiliary operators and tec hnicians. Such checklists or logs shall include any equipment under maintenance or test that by themselves could degrade a system critical to the prevention and mitigation of operational transients and accidents or initiate an operational transient (wha t to check and criteria for acceptable status shall be incl uded on the checklist).

c. A system shall be establis hed to evaluate the effectiv eness of the shift and relief turnover procedure (for example, periodi c independent verification of system

alignments).

Clarification

None.

Columbia Generating Station Position The control room operator's checklist is designed to do the following:

a. Ensure that critical plant parameters are monitore d and are within allowable limits, b. Ensure the availability and correct alignment of essential systems, and

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.1-10 c. Identify all systems or components which are in a degraded mode of operation and compare each length of time in the degraded mode to Technical Specifications acti on requirements.

The off-going and on-coming shift manager, control room superv isor, and on-coming control room operator positions will signify checklist status and content.

A checklist designed for balance-of-plant shift turnover will identify any equipment under maintenance or test which could either (a) by itself degrade a sy stem which is critical to the prevention and mitigation of opera tional transients and accidents or (b) initiate an operational transient.

The off-going or on-coming shift support supervisors and the on-coming equipment operators with rounds will signify checkli st status and content for the balance-of-plant checklists.

CGS established a system to evaluate the effectiveness of the shif t and relief turnover procedure.

This italicized text is historical and was provided to suppor t the application for an operating license.

With CGS receiving an operating license De cember 19, 1983, and going through test and startup phases prior to that date the shift and relief turnover pro cedures have been under continuous scrutiny for over 2 years. This has resulted in changes reviewed and accepted by the Plant Operations Committee to increase the efficiency and effectiveness of the procedures.

I.C.4 CONTROL ROOM ACCESS

Position (NUREG-0578 2.2.2.A)

The licensee shall make provisions for limiting acce ss to the control room to those individuals responsible for the direct operation of the nuclear power plan t (e.g., operations supervisor, shift supervisor, and control room operators), to technical advi sors who may be requested or required to support the operation, and to predesignated NRC personnel. Provisions shall include the following:

a. Develop and implement an administ rative procedure that establishes the authority and responsibility of the person in charge of the control room to limit access, and

b. Develop and implement procedures that establish a clear line of authority and responsibility in the control room in the event of an emergency. The line of succession for the person in charge of the control room shall be established and C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.1-11 limited to persons possessing a current se nior reactor operator's license. The plan shall clearly define the lines of communicati on and authority for plant management personnel not in direct command of operations, including those who report to stations outside of the control room.

Clarification

None.

Columbia Generating Station Position A Columbia Generating Station procedure has been implemented to establish the shift manager (SRO) and, in his absence, the control r oom supervisor (SRO) as the authority and responsibility for limiting access to the control room. Nonesse ntial personnel are excluded from the control room when th eir presence is hampering operations. Nonesse ntial personnel are defined as those not required by the shift manager to assi st in safe plant operation and may include anyone not normally assigned a shift control room position. If required, plant security

can be used to enforce the policy.

This position has been accepted in the NRC Safety Evaluation Report NUREG-0892, dated December 1982, section 13.5.1.8.

Additionally, procedures establish the same line of succession fo r control room authority and responsibility in the event of an emergency.

The procedures specifically address lines of communication and authority for management personnel not in direct command of operations and assigned responsibilities outside the control room. Instructions or orders impacting operations are reviewed by the operations manager and transmitted to the shift manager.

I.C.6 GUIDANCE ON PROCEDURES FOR VERIFYING CORRECT PERFORMANCE OF OPERATING ACTIVITIES

Position It is required (from NU REG-0660) that licensees' procedures be reviewed and revised, as necessary, to ensure that an effective system of verifying the correct performance of operating activities is provided as a means of reducing human e rrors and improving the quality of normal operations. This will reduce the frequency of occu rrence of situations that could result in or contribute to accidents. Such a verification system may include automatic system status monitoring, human verification of operations an d maintenance activitie s independent of the people performing the activity (see NUREG-0585, Recommendation 5), or both.

Implementation of automatic stat us monitoring if required will reduce the extent of human verification of operations and maintenance activitie s but will not eliminate the need for such C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.1-12 verification in all instances. The procedures adopted by the licensees may consist of two phases - one before and one afte r installation of automatic status monitoring equipment, if required, in accordance with Item I.D.3.

Clarification

Item I.C.6 of the NRC Task Action Plan (NUREG-0660) and Recommendation 5 of NUREG-0585 propose requiring that licensees' procedures be reviewed and revised, as necessary, to ensure that an effective system of verifying the correct performance of operating activities is provided. An acceptable program for verification of operating activities is

described below.

The American Nuclear Society has prepared a draft revision to ANSI Standa rd N18.7-1972 (ANS 3.2), "Administrative Controls and Qua lity Assurance for the Operational Phase of Nuclear Power Plants." A second proposed revision to Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operation)," wh ich is to be issued for public comment in the near future, will endorse th e latest draft revision to ANS 3.2 subject to the following supplemental provisions:

a. Applicability of the guidance of Sec tion 5.2.6 should be extended to cover surveillance testing in a ddition to maintenance.

b. In lieu of any designated senior reactor operator (SRO

), the authority to release systems and equipment for maintenance or surveillance testing or return-to-service may be de legated to an onshift SRO, provided provisions are made to ensure that the shif t supervisor is kept fully informed of system status.

c. Work permits involving tagging for ma intenance or surveillance testing are verified by the shift manager (or his designee) for correct implementation of

control measures. Independe nt verification by qualified individuals is made for installation or removal of temporary modifications such as jumpers, lifted leads or bypass lines. Routine independent ve rification of equipment status at the location of the equipment will be performed for return-to-service activities of all important safety-related equipment havi ng no control room st atus indications.

These verifications will be by qualified equipment operators.

d. Equipment control procedures should include assurance th at control room operators are informed of changes in equipment status and the effects of such changes.

e. For the return-to-service of equipmen t important to safety, a second qualified operator should verify proper systems a lignment unless functional testing can be C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.1-13 performed without compromising plant sa fety, and all equipm ent, valves, and switches involved in the activ ity are correctly aligned.

NOTE: A licensed operator possessing knowl edge of the systems involved and the relationship of the systems to plant safe ty would be a "qualified" person. The staff is investigating the level of qualification necessary for other operators to perform these functions.

For plants that have or will have automatic system status monitoring as discussed in Task Action Plan Item I.D.3, NUREG

-0660, the extent of human verification of operations and maintenance activities will be re duced. However, the need for such verification will not be eliminated in all instances.

Columbia Generating Station Position

Procedures implement an effec tive system for verification of operating activities important to safety. These procedures were implemented prior to fuel lo ad. The preparation of these procedures was guided by ANS 3.2 Section 5.2.6 and the following su pplemental provisions.

a. ANS 3.2 Section 5.2.6 will be appl ied to both maintena nce and technical specification surveillances as described below.

b. The shift manager has the designated responsibility for implementing procedures for release of systems and equipment for maintenance or surveillance testing and for return-to-service. Th is responsibility may be delegated to a licensed SRO. The shift manager will remain informed by reviewing records and receiving turnover.

c. Clearance tagging for maintenance or surveillance testing are independently verified by the shift manager (or his designee) for correct implementation of

control measures. Independe nt verification is also made for installation or removal of temporary modifications such as jumpers, lifted leads, or bypass lines on safety-related or fire protection systems not controlled by approved procedures. Routine independent verifica tion of equipment status at the location of the equipment will be performed fo r return-to-service activities of all safety-related and fire protection equipment having no control room status indications.

d. Equipment control procedures are implemented through the control room such that control room personnel are aware of changes being made in equipment status and the effect s of such changes.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 8 9, 0 1-000 B.1-14 e. Routine independent verifica tion of status at the location of safety-related or fire protection equipment is limited to return-t o-service activities performed prior to startups following refueling or long-term outages in accordance with the ALARA concept to limit accumulation of personnel radiatio n exposures. In addition to the above, independent verifi cation of the return-to-service position of safety-related locked valves will be made whenever their status is changed.

This position has been accepted in the NRC Safety Evaluation Report NUREG-0892, dated March 1982, section 13.5.1.8.

I.C.7 NSSS VENDOR REVIEW OF PROCEDURES

Position Obtain nuclear steam s upply system (NSSS) vendor review of low power testing procedures to further verify their adequacy.

This requirement must be met before fuel loading (NUREG-0694).

Clarification

None.

Columbia Generating Station Position

The NSSS vendor (General El ectric Company) has reviewed and documented the low power testing procedures, power ascens ion test procedures, and emergen cy procedures. This review considered the BWR Emergency Procedure guidelines submitted to the NRC on behalf of BWR Owners' Group on June 30, 1980, by letter from R. H.

Buchholz to D. G. Eisenhut.

This position has been accepte d in the NRC Safety Evaluati on Report NUREG-0892, dated March 1982, section 13.5.2.3 and c onfirmed in I&E Inspection 84-04.

I.C.8 PILOT MONITORING OF SELECTED EMERGENCY PROCEDURES FOR NEAR-TERM OPERATING LICENSE APPLICANTS

Position Correct emergency procedures, as necessary, based on NRC audit of selected plant emergency operating procedures (e.g., small-break LOCA, loss of feedwater, restart of engineered safety features following a loss of ac power, stream line break, or steam-generated tube rupture).

This action will be completed prior to iss uance of a full-power li cense (NUREG-0694).

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.1-15 Clarification

None.

Columbia Generating Station Position

CGS has developed procedures based on th e BWR Owners' Group Emergency Procedure Guidelines. These procedures are further addressed in response to I.C.1, Short-Term Accident Analysis and Procedure Revision.

This position has been accepte d in the NRC Safety Evaluati on Report NUREG-0892, dated December 1982, section 13.5.2.3.

I.D.1 CONTROL ROOM DESIGN REVIEWS

Position In accordance with Task Action Plan I.D.1, Control Room Design Reviews (NUREG-0660), all licensees and applicants for opera ting licenses will be required to conduct a detailed control room design review to identify and correct design deficiencies. This detailed control room design review is expected to take about a year.

Therefore, the Offic e of Nuclear Reactor Regulation (NRR) requires that those applicants for operating licenses who are unable to complete this review prior to issuance of a license make preliminary assessments of their control rooms to identify sign ificant human factors and instru mentation problems and establish a schedule approved by NRC for correcting deficiencies. These applicant s will be required to complete the more detailed control room reviews on the same schedule as licensees with operating plants (NUREG-0737).

Clarification

NRR is presently developing hu man engineering guidelines to assist each licensee and applicant in performing detailed control room review. A dra ft of the guidelines has been published for public comment as NUREG/CR-1580, "Human Engi neering Guide to Control Room Evaluation." The due date for comments on this draft document was September 29, 1980. NRR will issue the final version of the guidelines as NUREG-0700, by February 1981, after receiving, reviewing, and incorporati ng substantive public comments from operating reactor licensees , applicants for operating license s, human factors engineering experts, and other interested par ties. NRR will issue evaluation criteria, by July 1981, which will be used to judge the acceptability of the detailed reviews pe rformed and the design modification implemented.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.1-16 Applicants for operating licenses who will be un able to complete the detailed control room design review prior to issuance of a license are required to perf orm a preliminary control room design assessment to identify significant human factors problems. Applicants will find it of value to refer to the draft document NUREG/CR-1580, "Human Engineering Guide to Control Room Evaluation," in performing the preliminary assessment. NRR will evaluate the applicants' preliminary a ssessments including the performance by NRR of onsite review/audit.

The NRR onsite review/audit will be on a schedule consistent with licensing needs and will emphasize the following aspects of the control room:

a. The adequacy of information presented to the operator to reflect plant status for normal operation, anticipated operational occurrences, and accident conditions,

b. The groupings of displays and the layout of panels,

c. Improvements in the safety monitoring and human factors enhancement of controls and control displays,

d. The communications from the control r oom to points outside the control room, such as the onsite technical support cen ter, remote shutdow n panel, offsite telephone lines, and to other areas within the plant for normal and emergency operation,

e. The use of direct rather than derived signals for the presentation of process and safety information to the operator,

f. The operability of the plant from the control room with multiple failures of nonsafety-grade and n onseismic systems,

g. The adequacy of operating procedures and operator training with respect to limitations of instrumentation di splays in the control room,

h. The categorization of alarms, with unique definition of safety alarms, and

i. The physical location of th e shift supervisor's office eith er adjacent to or within the control room complex.

Prior to the onsite review/audit, NRR will require a copy of the applicant's preliminary assessment and additional information which will be used in formulatin g the details of the onsite review/audit.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.1-17 Columbia Generating Station Position CGS has undertaken an aggressive program to complete a control room review program in accordance with this task.

The schedule and activities for the review of the CGS Cont rol Room and submittal of an assessment report to th e NRR are as follows:

a. A preliminary assessment of CGS's Control Room based on the BWR Owners' Subgroup review program draft criteria and NRC draft document NUREG/CR-158 was submitted to NRR in January 1982.

b. A Detailed Control Room Design Revi ew (DCRDR) Preliminary Report based on a review of the CGS Control Room by the BWR Owners' Group and CGS in-house Human Factors Task Force against the BWR Owners' Group Control Room Design Review Program Plan and NUREG-0700 was submitted to NRR in April 1983.

c. Based on NRR reviews of the prelim inary DCRDR report and onsite audit, a Response to NRC Human Factors Engin eering Preliminary Design Assessment Audit Report was submitted to NRR in October 1983.

d. A CGS Control Room Design Review Program Plan documenting the CGS methodology and resources used, in accordance with NUREG-0700, was submitted in February 1984.

e. A DCRDR Final Report, per the CGS operating license was submitted to NRR on November 1, 1985, Letter GO2-85-758.

The schedule and activities for th e implementation of corrections for the CGS Control Room are as follows:

a. All major hardware and procedural findings noted during the preliminary DCRDR report were comple ted prior to fuel load.

b. All residual findings and findings noted in the DCRDR final report are scheduled to be completed duri ng the first refueling outage.

The NRC Safety Evaluation Report (SER) for the CGS DCRDR was issued as Reference

1. Energy Northwest responded to the SER in Reference

2. By Reference 3 Energy Northwest stated that all DCRDR items had b een implemented. In Reference 4 the NRC stated that based upon the Reference 3 submittal, they found that CG S satisfies all of the DCRDR requirements of Supplement 1 to NUREG-0737 and that TMI Item I.D.1

.2 was considered C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.1-18 closed (note that NUREG O737 and its Suppl ement 1 do not have an Item 1.D.1.2; only I.D.1).

References

1. Letter, G. W. Knighton (NRC) to G. C.

Sorensen (SS), "Detaile d Control Room Design Review (TAC No. 56181),"

dated October 13, 1987.

2. Letter, G. C. Sorensen (SS) to NRC, "N uclear Plant No. 2, Detailed Control Room Design Review (TAC No. 56181)," GO2 074, dated March 29, 1988.

3. Letter, G. C. Sorensen (SS) to NRC, "Nuclear Plant No. 2, Operating License NPF-21 Detailed Control Room Design Review (TAC No. 56181)," GO2-91-198, dated October 29, 1991.

4. Letter, P. L. Eng (NRC) to G. C. Sorense n (SS), "Status of TMI Item I.D.1.1, 'Detailed Control Room Design Review' (DCRDR) at Washington Public Po wer Supply System Nuclear Project No. 2 (WNP-2) (TAC NO. 56181)," dated November 13, 1991.

I.G.1 PREOPERATIONAL AND LOW-POWER TESTING

Position (NUREG-0660)

The objective is to increase the capability of th e shift crews to operate facilities in a safe and competent manner by assuring that training for plant changes and off-normal events is conducted. Near-term ope rating license facilities will be required to develop and implement intensified training exercises during the low-power testing programs. This may involve the repetition of startup tests on different shifts for training purposes. Based on experience from the near-term operating license facilities, requirements may be applied to other new facilities or incorporated into the plant drill requirement (Item I.A.2.5).

Review comprehensiveness of test programs.

NRR will require new operating licen sees to conduct a set of low-power tests to accomplish the requirements. The set of tests will be determined on a case-by-case basis for the first few plants. Then NRR will develop acceptance criteria for low-power test programs to provide "hands on" training for pl ant evaluation and off-normal events for each operating shift. It is not expected that all tests will be required to be conducte d by each operating shift. Observation by one shift of traini ng of another shift may be acceptable.

NRR will develop criteria in conjunction with initial near-term operating license reviews.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.1-19 Licensees will (1) define traini ng plan prior to loading fuel, and (2) conduct training prior to full-power operation.

Clarification

None.

Columbia Generating Station Position Energy Northwest committed to meet the intent of NUREG-0660 by performance of a special low power test subprogram which provided supplemental operator training in the areas of response to abnormal plant conditions and familiarity with critical systems. The special subprogram amplified the well-esta blished training value of the Startup Test Program (STP) through (1) instruction on the content, goals, and requirements of the program, (2) addition of selected special te sts to the STP to demonstrate abnormal scenarios and uses of critical systems and/or emergency operating proce dures to control them, and (3) utilization of the knowledge and experience gained during the STP in the training programs for future operators.

The overall Startup Test Program is outlined in Chapter 14 while the conduct of operations is discussed in Chapter 13. During the preoperational and power ascension test phases, the operations personnel were intimately involved in the performance of the various test procedures. With the impetu s provided by the responsible test phase organization, the operations staff was charged with establishi ng the required plant/sys tem conditions, initiating and controlling the desired test transient and returning th e plant/system to its normal condition. The operations staff provided the physical ability to accomplish the Startup Test Program. In this fashion, the completion of the Startup Test Program provided an unparalleled traini ng opportunity for the operators.

The following outlines those additional actions Energy Northwest implemented to augment the extensive training benefits inherent in the existing STP program:

I. Development and Implementation of a Training Course on the STP

A. General Classroom Instru ction (prior to testing)

1. STP Overview

a. Organization, Delineation of Responsibilities, Goals

b. Administrative and Emergency Procedures

c. Preop and Power Asce nsion Test Schedule C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.1-20 2. Review Selected STP Specifics, for example;

a. Pertinent Preop Test Purposes, Procedures, Anticipated Results

b. Integrated System Cold Functional Tests

c. Fuel Loading, Heatup, Powe r Ascension Test Purposes, Procedures, Anticipated Results

d. Special Test Subprogram Test Purposes, Procedures, Anticipated Results 3. Review Expected U tilization of STP Data

a. Documentation of Plant Safety

b. Feedback/Confirmation of Anticipated Results

B. Test Phase Instruction Performed by Test Director on a Shift Basis (during testing) 1. Review of the Imme diate Test Schedule

2. Discussion of the Impending Tests:

Procedures, Anticipated Results, Precautions

3. Review/Disseminate Plant Res ponse Data from Previous Shift(s)

C. Post-STP Completion Instruction Performe d by Test director (following testing)

1. Review Plant Design Changes/System Modifications Required

II. Development and Performance of a Special Test Subprogram A. Additional RCIC System Tests

1. RCIC Operation Following Loss of AC Power to the System

2. RCIC Operation to Prove DC Separation

B. Integrated Reactor Vessel Leve l Instrumentation Functional Test

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.1-21 C. Integrated Containment Pressure Instrumentation Functional Test D. Simulated Loss of Control and Instrument Air Test

E. Repetition of Some Normal STP Tests, for example:

1. Feedwater Pump Trip/Reci rc Runback Demonstration

2. Turbine Trip/Generator Load Re jection Within Bypass Valve Capacity

3. Pressure Regulator Setpoint Changes

4. Recirculation Pump Trips

5. Feedwater Level Setpoint Changes

III. Utilization of the STP Data

A. Refine the CGS Simulator Re sponse Models, as appropriate

B. Incorporate a Major Plant Transient Response Section in Operator Training Program, as appropriate

C. Update License Program Training and Requalific ation Material, as appropriate.

It was anticipated that every participating member of the operations staff would obtain valuable knowledge and experience through participation in the CGS Startup Test Program. Each received appropriate classroom instruction and through judicious schedu ling of tests, most were exposed to a variety of pl ant/system transient responses (or review of resu lts thereof).

The training received is continually reinforced through normal requalification program refinements. Future license candidates also benefit from the training material upgrades resulting from the STP experience.

With this program outline, Energy Northwest met the intent of NUREG-0660, Item I.G.1. Specific details of the training program, additional test proce dures, and documentation methods have been developed and are available for onsite NRC I&E review.

This position has been accepte d in the NRC Safety Evaluati on Report (NUREG-0892, dated December 1982, section 14.)

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-1 II.B.1 REACTOR COOLANT SYSTEM VENTS

Position Each applicant and licensee shall install reactor coolant system (RCS) and reactor vessel head high point vents remotely operated from the cont rol room. Although the purpose of the system is to vent noncondensable gases from the RCS which may inhibit core cooling during natural circulation, the vents must not lead to an unacceptable increase in the probability of a loss-of-coolant accident (LOCA) or a challenge to containment integrity. Since these vents form a part of the reactor coolant pressure bounda ry, the design of the ev ents shall conform to the requirements of Appendix A to 10 CFR 50, "General Design Criteria." The vent system shall be designed with sufficient redundancy that ensures a low probability of inadvertent or irreversible actuation.

Each licensee shall provide the following inform ation concerning the de sign and operation of the high point vent system:

a. Submit a description of the design, location, size, and power supply for the vent system along with results of analyses for LOCAs initiated by a break in the vent pipe. The results of the analyses should demonstrate compliance with the acceptance criteria of 10 CFR 50.46.

b. Submit procedures and supporting analysis for operator use of the vents that also include the information available to the operator for initiating or terminating vent usage.

Clarification

a. General

1. The important safety function enhanced by this venting capability is core cooling. For events beyond the pr esent design basis, this venting capability will substantially increase the plant's ab ility to deal with large quantities of noncondensable gas wh ich could interfere with core cooling. 2. Procedures addressing the use of the RCS vents should define the conditions under which the vents should be used as well as the conditions under which the vents should not be used. The procedures should be directed toward achieving a substantial increase in the plant being able to maintain core cooling without loss of containment integrity for events beyond the design basis. The use of vents for accidents within the C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-2 normal design basis must not result in a violation of the requirements of 10 CFR 50.44 or 10 CFR 50.46.

3. The size of the reactor coolant vents is not a critical issue. The desired venting capability can be achieved with vents in a fairly broad spectrum of sizes. The criteria for sizing a ve nt can be developed in several ways. One approach which may be considered is to specify a volume of noncondensable gas to be vented and in a specific venting time. For containments particular ly vulnerable to failure from large hydrogen releases over a short period of time, the necessity a nd desirability for contained venting outside the containment must be considered (e.g., into a decay gas collection and storage system).

4. Where practical, the RCS vents s hould be kept smaller than the size corresponding to the definition of LOCA (10 CFR 50, Appendix A). This will minimize the challenges to the emergency core cooling system (ECCS) since the inadvertent opening of a vent smaller than the LOCA definition would not require ECCS actuation, although it may result in

leakage beyond technical specificati on limits. On PWRs, the use of new or existing lines whose smallest orifice is larger than the LOCA definition will require a valve in series valve that can be closed from the control room to terminate the LOCA that would result if an open vent valve could not be reclosed.

5. A positive indication of valve position should be provided in the control room.

6. The reactor coolant vent system shall be operable from the control room.

7. Since the RCS vent will be part of the RCS pressure boundary, all requirements for the reactor pressure boundary must be met, and, in addition, sufficient redunda ncy should be incorporated into the design to minimize the probability of an inadvertent actuation of the system. Administrative procedures, may be a viable option to meet the single-failure criterion. For vents larger than the LOCA definition, an analysis is required to demonstr ate compliance with 10 CFR 50.46.

8. The probability of a vent path failing to close, once opened, should be minimized; this is a new requirement. Each vent must have its power supplied from an emergency bus. A single failure within the power and control aspects of the reactor coolan t vent system should not prevent C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-3 isolation of the entire vent system when required. On BWRs, block valves are not required in lines with safety valves that are used for venting. 9. Vent paths from the primary system to within containment should go to those areas that provide good mi xing with containment air.

10. The reactor coolant vent system (i.e., vent valves, block valves, position indication devices, cable terminations, and piping) shall be seismically and environmentally qualified in accordance with IEEE 344-1975 as supplemented by Regulatory Guide 1.

100, 1.92 and SEP 3.92, 3.43, and 3.10. Environmental qualificati ons are in accordance with the May 23, 1980 Commission Order and memorandum (CLI-80-21).

11. Provisions to test for operability of the reactor coolant vent system should be part of the design. Testing should be performed in accordance with subsection IWV of Section XI of the ASME Code for Category B

valves.

12. It is important that the displays a nd controls added to the control room as a result of this requirement not increase the potential for operator error.

A human-factor analysis should be pe rformed taking into consideration:

(a) The use of this information by an operator during both normal and abnormal plant conditions, (b) Integration into emergency procedures,

(c) Integration into operator training, and

(d) Other alarms during emergency and need for prioritization of alarms.

b. BWR Design Considerations

1. Since the BWR Owners' Group has suggested that the present BWR designs have an inherent capability to vent, a question relating to the capability of existing system s arises. The ability of these systems to vent the RCS of noncondensable gas generated during an accident must be demonstrated. Because of differences among the head vent systems for BWRs, each licensee or applicant should address the specific design features of this plant and compar e them with the generic venting capability proposed by the BWR Owners' Group. In addition, the ability C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-4 of these systems to meet the same requirements as the PWR vent system must be documented.

2. In addition to RCS venting, each BWR licensee should address the ability to vent other syst ems, such as the isolat ion condenser which may be required to maintain adequate core cooling.

If the production of a large amount of noncondens able gas would cause the loss of function of

such a system, remote venting of that system is required. The qualifications of such a venting sy stem should be the same as that required for PWR venting systems.

c. PWR Vent Design Considerations

1. Each PWR licensee should provide a capability to vent the reactor vessel head. The reactor vesse l head vent should be capable of venting noncondensable gas from the reactor ve ssel hot legs (to the elevation of the top of the outlet nozzle) and cold legs (through head jets and other leakage paths).

2. Additional venting capability is required for those portions of each hot leg that cannot be vented through the reactor vessel head vent or

pressurizer. It is impractical to ve nt each of the many thousands of tubes in a U-tube steam generator; however , the staff believes that a procedure can be developed that ensures sufficient liquid or steam can enter the U-tube region so that decay heat can be effectively removed from the RCS. Such operating procedures should incorporate this consideration.

3. Venting of the pressurizer is required to ensure its availability for system pressure and volume control. These are important considerations, especially during na tural circulation.

Columbia Generating Station Position

The reactor coolant vent line is located at the very top of the reactor vessel as shown in Figure 3.6

-5 1. This 2-in. line contains two safety-r ela t ed C l ass 1E m o tor-operated valves (MS-V-1 and MS-V-2) that are operated from th e control room. The location of this line permits it to vent the entire RCS normally connected to the reactor pres sure vessel (RPV), with the exception of the reactor coolant isolation cooling (RCIC) head spray piping which comprises approximately 0.6 ft 3 of volume above the elevation of the RPV. This small volume was considered in the original design of the RCIC system and is of no consequence to its operation. In addition, since this vent line is part of the original design for the unit, it has already been considered in all the design basis accident analyses contained elsewhere in the FSAR.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-5 The Columbia Generating Station (CGS) BWR/5 is provided with 18 power-operated safety grade relief valves which can be manually operated from the control room to vent the RPV.

The point of connection to the vent lines (main st eam lines) from near the top of the vessel to these valves is such th at accumulation of gases above that poi nt in the vessel will not affect natural circulation of the reactor core.

These power-operated relief valv es satisfy the intent of th e NRC position. Information regarding the design, qualification, power source, etc., of these valves is provided in Section 5.2.2.

The BWR Owners' Group position is that the requirement of single failure criteria for prevention of inadvertent actuation of these valv es, and the requirement that power be removed during normal operation, are not applicable to BWRs. These valves serve an important function in mitigating the effects of transients and at CGS provide AS ME code overpressure protection. Therefore, the add ition of a second "block" valve to the vent lines would result in a less safe design and a violati on of the code. Moreover, the inadvertent opening of a relief valve in a BWR is a design basis event and is a controllable transient.

In addition to these power-ope rated relief valves, the CGS BWR/5 includes various other means of high-point venting. Among these are

a. Normally closed reactor vessel head vent valves, operable from the control room, which discharge to the drywell;

b. Normally open reactor head vent line, which discharges to a main steam line;

c. Main steam-driven RCIC system turbines, operable from the control room, which exhaust to the suppression pool; and

d. Main steam-driven reactor feedwate r pumps operable from the control room, which exhaust to the plant condenser wh en not isolated.

Condenser gases are continuously processed thro ugh the offgas system.

Although the power-operated relief valves fully sa tisfy the intent of th e venting requirement, these other means also provide protection against the accumulation of noncondensables in the RPV.

Under most circumstances, no sele ction of vent path is necessary because the relief valves [as part of the automatic depressurization system (ADS)], high-pressure core spray (HPCS), and RCIC will function automatically in their designed modes to ensu re adequate co re cooling and provide continuous venting to the suppression pool.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-6 Analyses of inventory-threateni ng events with very severe degr adations of system performance have been conducted. These were submitted by GE for the BWR Owners' Group to the NRC Bulletins and Orders Task For ce on November 30, 1979. The f undamental conclusion of these studies was that if only one ECCS is injecting into the reactor, adequate core cooling would be provided and the production of large quantities of hydrogen would be avoided. Therefore, it is not desirable to interfere with ECCS functions to prevent venting.

The small-break accident (SBA) guidelines emphasize the use of HPCS/RCIC as a first line of defense for inventory-threateni ng events which do not quickly depressurize the reactor. If these systems succeed in maintaining inventory, it is desira ble to leave them in operation until the decision to proceed to cold shutdown is made. Thus the reactor will be vented via RCIC turbine steam being discharged to the suppression pool. Termina tion of this mode of venting could also terminate inventory makeup if the HPCS had failed also. This would necessitate reactor depressurization via the safety/relief valve (SRV), which of course is another means of venting.

If the HPCS/RCIC are unable to maintain inventory, the SBA guidelines call for use of ADS or manual SRV actuation to depressurize the reacto r so that the low-pressure coolant injection (LPCI) and/or low-pressure core spray (LPCS) systems can inject water.

Thus, the reactor would be vented via the SRV to the suppression pool. Termination of this mode of venting is not recommended. It is preferable to remain unpressurized; however , if inventory makeup requires HPCS or RCIC restart, that can be a ccomplished manually by the ope rator. It is more desirable to establish and mainta in core cooling than to avoid venting. If the HPCS/RCIC and SRVs are not operable (a very degraded a nd extremely unlikely case), another emergency means of venting the reactor must be used. It is emphasized, however, that such emergency venting would be in the interest of core c ooling and, therefore, could be employed under Emergency Procedure Guidelines.

It is thus concluded that there is no reason to interfere with E CCS operation to avoid venting.

It is further concluded that the Emergency Procedure Guidelines, by correctly specifying operator actions for HPCS, RCIC , and SRV operation, also correctly specify operator actions to vent the reactor.

In the event of HPCS failure a nd continued vessel pressurization, the effect of noncondensables in the RCIC turbine steam was evaluated for three cases:

1. Continuous evolution of noncondensables due to radiolysis,

2. Quasi-continuous evolution of noncondensables due to core heatup, and

3. The presence of a quantity of noncondensables in the reactor at the time of HPCS/RCIC startup.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-7 Case 1 is a normal opera ting mode for RCIC and is of no concern.

For Case 2 to exist, the core must be uncovered. Such a cond ition requires multiple failures as shown in the degraded cooling analyses. Core uncove ry is prevented (or cladding heatup into the rapid oxidation range is pr evented) when only one ECCS is operating. For small pipe break or a loss of feedwater, wh ich would allow the reactor to remain at pressure, the HPCS and/or RCIC pumps would maintain inventory and there would be no substantial hydrogen production. If neither HPCS nor RCIC could maintain inventory, the reactor would be

automatically or manually depressurized via SRVs (or via the break, for larger breaks). Low-pressure water injection systems (LPCI or LPCS) would then make up inventory. With the core covered neither the ra pid generation of nonc ondensables nor their accumulation would be possible.

The performance of RCIC under Case 3 is of concern only if there has been a very substantial production of hydrogen due to core uncovery and there is a need to start the RCIC. This is extremely unlikely and an intolerable circumstance, because it could arise only if the core were allowed to remain uncovered for a long period with the reactor at high pressure. Automatic depressurization system opera tion and explicit operating inst ructions and the Emergency Operator Guidelines are intended to preclude this. If the level has falle n with the reactor at high pressure, the vessel would be depressurized either automa tically or manually to permit low pressure injection indepe ndent of RCIC performance.

In the post-LOCA condition, it is possible to have noncondensable gases come out of solution while operating the residual heat removal (RHR) system. These gases wo uld accumulate at the top of the RHR heat exchanger si nce this is a system high point and an area of relatively low flow. Gases trapped here will be vented thr ough a 2-in. vent line w ith two safety-related Class 1E motor-operated valves (MO-F073A and MO-F074A or MO-F073B and MO-F074B) operated from the control room (as shown in Figure 5.4-15). As this vent line and associated valves are part of the original design, they have also been consider ed in the design basis accident analysis contained elsewhere in the FSAR.

The result of a break in the SRV discharge piping, or any of the other pipe lines for the systems enumerated above, would be the same as a small steam line brea

k. A complete steam line break is part of the design basis, and smaller size breaks have been shown to be of lesser severity. A number of reactor system blow downs due to stuck-open relief valves (also equivalent to a small steam line break) have confirmed this in practice. Thus no new analyses are required to show conf ormance with 10 CFR 50.46.

Because the relief valves a nd RCIC will vent the reactor continuously, and because containment hydrogen calculations in normal safety analysis calculations assu me continuous venting, no special analyses are required to demonstrate "that the direct venting of noncondensable gases with perhaps high hydrogen concentrati ons does not result in violation of combustible gas concentrati on limits in containment."

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-8 Conclusion and Comparis on with Requirements

The conclusion from this vent evaluation for CGS is as follows:

a. Reactor vessel head vent valves exist to relieve head pressu re (at shutdown) to the drywell via remote operator action;

b. The reactor vessel head can be vented during operating conditions via the SRVs to the suppression pool;

c. The RCIC system provides an additiona l vent pathway to the suppression pool;

d. The size of the vents is not a critical issue because BWR SRVs have substantial capacity, exceeding the full power steaming rate of the nuclear boiler;

e. The SRVs vent to the containment suppression pool, wh ere discharged steam is condensed without causing a rapid containment pressure

/temperature transient;

f. The SRVs are not smaller than the NRC defined small LOCA. Inadvertent actuation is a design basis event and a demonstrated controllable transient;

g. Inadvertent actuation is of course undesirable, but since the SRVs serve an important protective function, no steps such as removal of power during normal operation should be taken to prevent inadvertent actuation;

h. A direct indication of SRV position is provided in the control room per Table 7.5-1, item 21. Temperature s e nsors in the discharge lines confirm possible valve leakage;

i. Each SRV is remotely operable from the control room;

j. Each SRV is seismically and Class 1E qualified;

k. Block valves are not required, so block valve qualific ations are not applicable;

l. No new 10 CFR 50.46 conformance calculations are required because the vent provisions are part of the systems in th e plant's original design and are covered by the original design bases; and

m. Plant procedures govern the operator's us e of the relief mode for venting reactor pressure. These procedures are available for NRC inspection at the plant.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.2-9 This position has been accepted in the NRC Safety Evaluation Report NUREG-0892, dated December 1982, section 5.4.3.1.

II.B.3 POSTACCIDENT SAMPLING CAPABILITY

Position A design and operational review of the reactor coolant and c ontainment atmosphere sampling line systems shall be performed to determine the capability of personne l to promptly obtain (less than 1 hr) a sample under accident conditi ons without incurring a radiation exposure to any individual in excess of 3 and 18.75 rem to the whole body or extremities, respectively. Accident conditions should assume a Regulatory Guide 1.3 or 1.4 releas e of fission products.

If the review indicates that personnel could not promptly and safely obtain the samples, additional design features or shielding shou ld be provided to meet the criteria.

A design and operational review of the radiological spectrum analysis facilities shall be performed to determine the capability to promptly quantify (in less than 2 hr) certain radionuclides that are indicators of the degree of core damage. Suc h radionuclides are noble gases (which indicate cladding failure), i odines and cesiums (which indicate high fuel temperatures), and nonvolatile isotopes (which indicate fuel melting). The initial reactor coolant spectrum should correspond to a Regulatory Guide 1.3 or 1.4 release. The review should also consider the effects of direct radiation from piping and components in the auxiliary building and possible contamination and direct radiation fr om airborne effluents. If the review indicates that the analyses re quired cannot be performed in a prompt manner with existing equipment, then design modifications or equipment procurement shall be undertaken to meet the criteria.

In addition to the radiological analyses, cert ain chemical analyses are necessary for monitoring reactor conditions.

Procedures shall be provided to perform boron and chloride chemical analyses assuming a highly radioactive initial sample (Regulatory Guide 1.3 or 1.4 source term). Both analyses shall be capable of being comp leted promptly (i.e., the boron sample analysis within an hour and the chloride sample analysis within a shift).

Clarification The following items are clarifications of requirements identified in NUREG-0578, NUREG-0660, or the September 13 and October 30, 1979, clarification letters.

a. The licensee shall have the capability to promptly obtain reactor coolant samples and containment atmosphere samples. The combined time allotted for sampling and analysis should be 3 hr or less from the time a decision is made to take a sample.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.2-10 b. The licensee shall establish an onsite radiological and chemical analysis capability to provide, within the 3-hr time frame established above, quantification of the following:

1. Certain radionuclides in the reactor coolant and contai nment atmosphere that may be indicators of the degr ee of core damage (e.g., noble gases, iodines and cesiums, and no nvolatile isotopes),

2. Hydrogen levels in the containment atmosphere,

3. Dissolved gases (e.g., H 2), chloride (time allotted for analysis subject to discussion below), and boron concentration of liquids, and

4. Alternatively, have inline monitoring capabilities to perform all or part of the above analyses.

c. Reactor coolant and containment atmo sphere sampling during postaccident conditions shall not require an isolated auxiliary system [e.g., the letdown system, reactor water cleanup (RWCU) syst em] to be placed in operation to use the sampling system.

d. Pressurized reactor cool ant samples are not required if the licensee can quantify the amount of dissolved gases with unpre ssurized reactor coolant samples. The measurement of either total dissolved gases or H 2 gas in reactor coolant samples is considered adequat

e. Measuring the O 2 concentration is recommended but is not mandatory.

e. The time for a chloride analysis to be performed is dependent on two factors:

(1) if the plant's coolant water is seawater or brackish water, and (2) if there is only a single barrier between primary containment systems and the cooling water. Under both of the above conditi ons the licensee shall provide for a chloride analysis within 24 hr of the sa mple being taken. For all other cases, the licensee shall prov ide for the analysis to be co mpleted within 4 days. The chloride analysis does not have to be done onsite.

f. The design basis for plant equipmen t for reactor coolant and containment atmosphere sampling and analysis must assume that it is possible to obtain and analyze a sample without radiation expos ures to any individual exceeding the criteria of General Design Criterion (GDC) 19 (Appendix A, 10 CFR 50) (i.e., 5 rem whole body, 75 rem extremities). (N ote that the design and operational review criterion was c hanged from the operational limits of 10 CFR 20 (NUREG-0578) to the GDC 19 criterion (October 30, 1979, letter from H. R. Denton to all licensees.)

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 B.2-11 g. The analysis of primary coolant sample s for boron is required for PWRs. (Note that Revision 2 of Regulatory Guide 1.97, when issued, will likely specify the need for primary coolant boron analysis capability at BWR plants.)

h. If inline monitoring is used for any sampling and analytical capability specified herein, the licensee shall provide backup sampling through grab samples and shall demonstrate the capability of analyzing the samples. Established planning for analysis at offsite fac ilities is acceptable. Equi pment provided for backup sampling shall be capable of providing at least one sa mple per day for 7 days following onset of the accident and at least one sample per week until the accident condition no longer exists.

i. The licensee's radiological and chemical sample analysis capability shall include provisions to:

1. Identify and quantify the isotopes of the nuclide categories discussed above to levels corresponding to the source terms given in Regulatory Guides 1.3 or 1.4 and 1.7. Where necessary and practicable, the ability to dilute samples to provide capability for measurement and reduction of personnel exposure should be provided. Sensiti vity of onsite liquid sample analysis capability should be su ch as to permit measurement of nuclide concentration in the range from approximately 1 Ci/g to 10 Ci/g.

2. Restrict background levels of radiat ion in the radiological and chemical analysis facility from sour ces such that the sample analysis will provide results with an a cceptably small error (approxim ately a factor of 2).

This can be accomplished through the use of sufficient shielding around samples and outside sources, and by th e use of ventilation system design which will control the presence of airborne radioactivity.

j. Accuracy, range, and sens itivity shall be adequate to provide pertinent data to the operator in order to describe radiologi cal and chemical status of the reactor coolant systems.

k. In the design of the postaccident sa mpling and analysis c apability, consideration should be given to the following items:

1. Provisions for purging sample lines , for reducing plateout in sample lines, for minimizing sample loss or distortion, for preventing blockage of sample lines by loose material in the RCS or containment, for appropriate disposal of the samples, and for flow restrictions to limit C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-12 reactor coolant loss from a rupture of the sample line. The postaccident reactor coolant and containment atmosphere samples should be representative of the reactor c oolant in the core area and the containment atmosphere following a tr ansient or accident. The sample lines should be as short as possible to minimize the volume of fluid to be

taken from containment. The resi dues of sample collection should be returned to containment or to a closed system.

2. The ventilation exhaust from the sampling station should be filtered with charcoal adsorbers and high-efficien cy particulate air (HEPA) filters.

3. Guidelines for analytical or in strumentation range are given in Table II.B.3-1.

Columbia Generating Station Position This italicized information is historical and was provided to support the application for an operating license. The FSAR contains a description of the pos taccident sampling system in Section 11.6. Columbia Generating Station is using a General Electric postaccident sampling system capable of sampling the primary contai nment and reactor building atmos phere and of obtaining liquid samples from the reactor, RHR loops, and various reactor building sumps. This system is designed to obtain grab sample s which may be analyzed onsite or transported to offsite facilities for more detailed analysis if necessary. The sample sta tion is located in the radwaste building and is shielded to reduce radiation exposure rates to the operator. All remote-operated valves ar e controlled from this area. Le ad pigs are provided for radiation protection when transporting samples either to onsite facilities or offsite. A more detailed description follows.

Gas samples will be obtained from locations in the drywell, the suppression pool atmosphere, and from the secondary containment atmosphere. The sample system is designed to operate at pressures ranging from subatmo spheric to maximum design pressures of the primary and secondary containment. Heat-tra ced sample lines are used outs ide the primary containment to prevent precipitation of moisture and resultant lo ss of particulates and iodines in the sample lines. The gas samples may be passed through a particulate filte r and silver zeolite cartridge for determination of particulate activity and i odine activity by subse quent analysis of the samples on a gamma spectrometer system. Alternatively, the sample flow bypasses the particulate/iodine sampler, is chilled to remove mo isture, and a 15-ml grab sample can be taken for determination of gaseous r adioactivity and for gas composition by gas chromatography. This size sample vial has been adopted for all gas samples to be consistent with present offgas sample vial counting factors.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-13 Reactor coolant samples will be obtained from tw o points in the jet pump pressure instrument system when the reactor is at pressure. The jet pump pressure system has been determined to be an optimum sample point for accident conditions. The pressure taps ar e well protected from damage and debris. If the recirculation pumps are secured, th e water level will be raised about 18 in. above normal. This pr ovides natural circulation of the bulk coolant past the taps.

Also, the pressure taps are loca ted sufficiently low to permit sa mpling at a reactor water level even below the lower core support plate.

A single sample line is also connected to both l oops in the RHR system.

This provides a means of obtaining a reactor coolant sample when the re actor is depressurized and at least one of the RHR loops is operated in the shutdown cooling mode. Similarly, a suppression pool liquid sample can be obtaine d from the RHR loop lined up in th e suppression pool cooling mode. Samples from the five drain sumps in the reactor building are also available.

The sample system isolation val ves are controlled from the lo cal control panel. The sample system is designed for a purge flo w of 1 gpm, which is sufficient to maintain turbulent flow in the sample line. Purge flow is returned to the suppression pool. The high flush flow also serves to alleviate cross-contamination of the samples when switching from one sample point to another. All liquid samples are taken into septum bottle s mounted on sampling ne edles. The sample station is basically a bypass loop on the sample purge line. In the normal lineup, the sample flows through a conductivity cell (readable range 0.1 to 1000 S/cm) and then through a ball valve bored out to 0.10-ml volume. Flow through the sample panel is established, the valve is rotated 90°, and a syringe is used to flush the sample plus a measured volume of diluent (generally 10 ml) through the valve and into the sample bottle. This provides a dilution of 100:1 to the sample. Alternativ ely, the valve sampling sequence can be repeated 10 times to provide a 1-ml sample diluted 10:1. The samp le is transported to th e laboratory for further dilution and subsequent analysis.

Alternatively, the sample flow can be diverted through a 70-ml bomb to obtain a large pres surized volume. This 70-ml volume can be circulated and depressurized into a known volume gas expansion chamber. The pressure change in this chamber will be used to calculate the total dissolved gases in the reactor coolant. A grab sample of these gases may be taken through a septum port fo r subsequent analysis. Ten milliliter aliquots of this degasse d liquid can also be taken for on or offsite chemical analyses requiring a relatively large sa mple. A radiation monitor in the liquid sample enclosure monitors liquid flow from the sample station to provide immediate assess ment of the sample activity level. This monitor also provides information as to the effectiveness of the demineralized water flushing of the sample sy stem following sample ope ration. The control instrumentation is installed in two 2 ft x 2 ft x 6 ft high standard cabinet control panels. One panel contains the conductivity and radiation level readouts. Another control panel contains the flow, pressure and temperat ure indicators, and the various control valves and switches.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-14 A graphic display panel, installed directly below th e main control panel, shows the status of the pumps and valves at all times.

The panel also indicates the re lative position of the pressure gauges and other items of concern to the operator. The use of this panel will improve operator comprehension and assist in trouble-shooting operation.

Appropriate sample handling tools, a gas sampler vial posit ioner and gas vial cask are available to the operator at the sampling station.

The gas vial is installed and removed by use of the vial positioner through the front of the gas sampler. The vial is then manually placed down in the cask with the positione r which allows the vial to be maintained about 3 ft from the individual performing the operation.

The small-volume (10 ml) liquid sample is remotely obtained through the bottom of the sample station by use of the small-volu me cask and cask positioner. Th e cask positioner holds the cask and positions the cask directly unde r the liquid sampler. The sample vial is manually raised within the cask to engage the hypodermic needles.

When the sample vi al has been filled, the bottle is manually withdrawn into the cask. The sample vial is always contained within lead shielding during this operation.

The cask is then lowered and se aled prior to transport to the laboratory.

A large-volume cask and cask positioner is available for transporting large liquid samples.

A 21-ml bottle is contained within a lead shielded cask. This sa mple bottle is raised from its location in the cask to the samp le station needles for bottle filli ng. The sample station will only deliver 10 ml to this sample bo ttle. When filled, the bottle is withdrawn into the cask. The sample bottle is always shielded by 5 to 6 in. of lead when in position under the sample station and during the fill and withdraw cycles, thus reducing operator exposure.

The cask is transported to th e required position under the sample station by a dolly cask positioner. When in position this cask is hydraulically eleva ted approximately 1.5 in. by a small hand pump for contact with the sample station shielding under the liquid sample enclosure floor. The sample bo ttle is raised, held, and lowered by a simple push/pull cable.

The cask is sealed by a threade d top plug that inserts above the sample bottle. The weight of this large-volume cask is approximately 700 lb.

The particulate filters and iodine cartridges ar e removed via a drawer arrangement. The quantity of activity which is a ccumulated on the cartridges is c ontrolled by a combination of flow orificing and time sequence control of the fl ow valve opening. In addition, the deposition of iodine is monitored during sampling using a radiation detector instal led adjacent to the cartridge. These samples will hence be limited to activit y levels which will normally not require shielded sample carriers to transport the sa mples to the laboratory.

The power supply to the sample station and all associated equipment will not be shed during accident conditions. The system design is such that a sample can be drawn and analyzed within the required 3 hr, afte r a 1 hr preparation time.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-15 The postaccident sampling station will provid e conductivity measurements in line as an indicator of liquid chemical concentrations and changing chemical conditions. The system allows collection of grab sa mples for gas analysis of O 2 , N 2 , H 2, and direct gamma spectrometric determination of a liquots of gas samples. The sy stem also allows collection of iodine samples on a silver zeolite cartridge to minimize noble gas interference in the determination of iodine isotopi c content. Liquid samples will be analyzed for pH using a semimicro pH electrode and additionally analyzed for bor on and chloride using ion chromatography. An aliquot of the sample may also be analyzed for gro ss activity or isotopic content by gamma ray spectrometry. All l aboratory analysis meet Regulatory Guide 1.97 requirements for sensitivity and range, with the exception of th e range for dissolved gases.

However, the analytical capability fo r dissolved gases is consistent with the maximum dissolved gas concentrations expected for BWRs.

The postaccident sample system will be used quarterly for operability testi ng. During this testing a reactor coolant sample will be taken and analyzed for gamma isotopic content. In addition, a containment atmosphere sample will be taken and analyzed for gas composition and gamma isotopic content. The results of these analyses will be compared, where possible, to results obtained through normal plant sampling systems to verify the representatives of postaccident system samples. Classroom and practical facto rs training will be provided on system operation, as well as proper handling and an alysis of highly r adioactive samples.

Refresher training will be provided annually.

A yearly drill will be performed in which the postaccident sample system will be used to obtain samples. These samples will be drawn, transported, and analyzed for accident parameters as if they were postaccident hi ghly radioactive samples.

Based on information developed by General Electric, Energy Northwest has developed plant-specific procedures for th e determination of the extent of core damage under accident conditions. The procedures prov ide for distinguishing between fuel cladding failure and fuel melt based on isotopes present and concentration. The extent of damage is based on concentrations present of isotopic mixture of xenon, krypton, iodine, and cesium.

The estimated maximum potential wh ole body dose to retrieve a reactor coolant sample under worst-case accident conditi ons is 0.36 rem; the source being ai rborne noble gas activity in the radwaste building from effluent releases. Lapsed time is about 1 hr.

The maximum dose rate from a 0.1 ml reactor coolant sample (1 hr decay) in a 4-in.-thick lead transport cask is less than 5 mR/hr at 1 ft. Expos ure to analyze a sample is expected to be less than 100 mR.

All valves used are fully qualified for the environment in wh ich they are located inside and outside reactor containment.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-16 Power for the postaccident sampling equipment is supplied from either Division 1 or Division 2 critical power sources and will be available during accident conditions.

The staff review of this position in NUREG-0 892, dated December 1982, recognized several issues requiring resolution and consolidated them in Licensi ng Condition 9.

Subsequent Energy Northwest submittals, primarily Amendment 23 to the FSAR, resulted in the staff finding the postaccident sampling system acceptable in Supplement 4 NUREG-0892, section 9.3.2.4. A requirement to have the system comple ted and operable prior to exceeding 5% power was made a condition to the license (NPF-21 issued December 20, 1983). Energy Northwest letter GO2-84-272 dated April 27, 1984, reported the sy stem completed and operable thus satisfying the licensing condition.

II.F.1.3 Containment High-Range Radiation Monitor

Position Radiation level monitors w ith a maximum range of 10 8 R/hr shall be insta lled in containment. A minimum of two such monitors that are physi cally separated shall be provided. Monitors shall be developed and qua lified to function in an accident environment.

Clarification

a. Provide two radiation monitor systems in containment which are documented to meet the requirements of Table II.F.1-3.

b. The specification of 10 8 R/hr in the above position was based on a calculation of postaccident containment radi ation levels that included both particulate (beta) and photon (gamma) radi ation. A radiation detector that responds to both beta and gamma radiation cannot be qua lified to post-LOCA containment environments but gamma-sensitive instru ments can be so qualified. To follow the course of an accident, a containm ent monitor that measures only gamma radiation is adequa te. The requirement was revi sed in the October 30, 1979, letter to provide for a photon-only m easurement with an upper range of 10 7 R/hr.

c. The monitors shall be located in cont ainment(s) in a manner as to provide a reasonable assessment of area radiation conditions inside containment. The monitors shall be widely separated so as to provide independent measurements and shall "view" a large fr action of the containment volume. Monitors should not be placed in areas which are protect ed by massive shielding and should be reasonably accessible for replacement, maintenance, or calibration. Placement C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-17 high in a reactor building dome is not recommended because of potential maintenance difficulties.

d. For BWR Mark III containments, two su ch monitoring systems should be inside both the primary containment (drywell) and the secondary containment.

e. The monitors are required to respond to gamma photons with energies as low as 60 keV and to provide an essentially fl at response for gamma energies between 100 keV and 3 MeV, as specified in Table II.F.1-3. Monitors that use thick shielding to increase the upper range will underestimat e postaccident radiation levels in containment by several orders of magnitude because of their

insensitivity to low energy gammas and are not acceptable.

Columbia Generating Station Position This italicized text is historical and was provided to suppor t the application for an operating license. The FSAR contains descr i ptions for these monitors in S ections 7.5.1.5.3 , 7.5.2.2.3 , 11.5.2.2.3.2 , and Tab l e 7.5-1, item 8. Columbia Generating Station conc urs with the intent of this position and has installed high range gamma detection monitors in the following primary containment locations:

a. 515 ft level Azimuth 290°and b. 516 ft level Azimuth 51.5°.

The detectors are unshielded and mounted on the wa ll in areas least influenced by shielding due to surrounding piping, etc. They are accessible for calibration and will be calibrated according to the Technical Specifications. Plant drawings will be revised to reflect their addition and location.

This position has been accepte d in the NRC Safety Evaluati on Report, NUREG-0892, dated December 1982, section 12.3.4.1.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-19 Table II.F.1-3 Containment High-Range Radiation Monitor

Requirement - The capability to detect and measure the radiation level within the reactor containment during and following an accident. Range - 1 rad/hr to 10 8 rads/hr (beta and gamma) or alternatively 1 R/hr to 10 7 R/hr (gamma only). Response - 60 keV to 3 MeV photons, w ith linear energy response +/-20%) for photons of 0.1 MeV to 3 MeV. Inst ruments must be accurate enough to provide usable information. Redundant - A minimum of two physically separated monitors (i.e., monitoring widely separated spaces within containment).

Design and qualification - Category 1 instruments as described in Appendix A, except as listed below. Special calibration - In situ calibration by electronic signa l substitution is acceptable for all range decades above 10 R/hr. In situ calibration for at least one decade below 10 R/hr shall be by means of calibrated radiation source. The original laboratory calibration is no t an acceptable position due to the possible differences after in situ installation. For high-range calibration, no adequate sources exist, so an alternate was provided.

Special environmental qualifications - Calibrate and type-test representative specimens of detectors at sufficient points to demonstrate linearity through all scales up to 10 6 R/hr. Prior to initial use, certify calibration of each detector for at least one point per decade of range between 1 R/hr and 10 3 R/hr.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-21 II.F.1.4 Containment Pressure Monitor Position A continuous indication of containment pressure shall be provided in the control room of each operating reactor. Measurement and indication capability shall include three times the design pressure of the containment for concrete, four times the design pr essure for steel, and -5 psig for all containments.

Clarification

a. Design and qualification criteria are outlined in Appendix A;

b. Measurement and indication capability shall extend to 5 psia for subatmospheric containments;

c. Two or more instruments may be used to meet requirements. However, instruments that need to be switched from one scale to another scale to meet the range requirements ar e not acceptable;

d. Continuous display and reco rding of the containment pr essure over the specified range in the control room is required; and

e. The accuracy and response tim e specifications of the pr essure monitor shall be provided and justified to be adequate for their intended function.

Columbia Generating Station Position This italicized information is historical and was provided to support the application for an operating license. The FSAR contai ns descriptions for these mon itors in the following sections:

7.5.1.5.1 , 7.5.2.2.3 , and Table 7.5-1, item 37. Columbia Generating Station has de signed a system to meet this cr iteria. A description of the system is provided in Section 7.5. The range, accuracy, and response time of these instruments are Range = -5 to +3 psig 0 to 25 psig 0 to 180 psig Instrument accuracy (loop) = +/-2% of full scale

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-22 Response time = 0 to 100% fu ll scale in less that 1 sec This position has been accepte d in the NRC Safety Evaluati on Report NUREG-0892, dated December 1982, sections 6.2.1.1.1 and 7.5.2.6.

II.F.1.5 Containment Water Level Monitor Position A continuous indication of containment water level shall be provid ed in the control room for all plants. A narrow range instrume nt shall be provided for PWRs and cover the range from the bottom to the top of the containment sump. A wide range instrument shall also be provided for PWRs and shall cover the range from the bottom of the containment to the elevation equivalent to a 600,000-gal capacity. For BWRs, a wide range instrument shall be provided and cover the range from the bottom to 5 ft above th e normal water level of the suppression pool.

Clarification

a. The containment wide-range water leve l indication channels shall meet the design and qualification criteria as outlined in Appendix A. The narrow-range channel shall meet the requirements of Regulatory Guide 1.89;

b. The measurement capabilit y of 600,000 gal is based on recent plant designs.

For older plants with sma ller water capacities, license es may propose deviations from this requirement based on the av ailable water supply capability at their plant; c. Narrow-range water level monitors are required for all sizes of sumps but are not required in those plants that do not contain sumps inside the containment;

d. For BWR pressure-suppression containments, the ECCS suction line inlets may be used as a starting refe rence point for the narrow-range and wide-range water level monitors, instead of the bottom of the suppression pool; and

e. The accuracy requirements of the water level monitors sha ll be provided and justified to be adequate for their intended function.

Columbia Generating Station Position This italicized information is historical and was provided to support the application for an operating license. The FSAR contai ns descriptions for these mon itors in the following sections:

7.5.1.5.7 , 7.5.2.2.3 , and Table 7.5-1, item 14.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-23 In Columbia Generating Station, the variable to be measured is the suppression chamber water level. Columbia Generating Station has expanded its s uppression chamber water level instruments to cover this requirement. A description is provided in Section 7.5. The accuracy and response time of this instrument are Instrument accuracy = +/- of full scale Instrument response time = 0 to 100%

of full scale in less than 1 sec This position has been accepte d in the NRC Safety Evaluati on Report NUREG-0892, dated December 1982, sections 6.2.1.1.2 and 7.5.2.6.

II.F.1.6 Containment Hydrogen Monitor Position A continuous indication of hydr ogen concentration in the containment atmosphere shall be provided in the control room. Measurement capab ility shall be provided o ver the range of 0 to 10% hydrogen concentrati on under both positive and negative ambient pressure.

Clarification

a. Design and qualification criteria are outlined in Appendix A, b. The continuous indication of hydrogen concentration is not required during normal operation, If an indication is not available at all times, continuous indication and recording shall be functioning within 30 minutes of the initiation of safety injection, and

c. The accuracy and placement of the hydrogen monitors shall be provided and justified to be adequate for their intended function.

Columbia Generating Station Position This italicized information is historical and was provided to support the application for an operating license. The FSAR contai ns descriptions for these mon itors in the following sections:

6.2.5.2.2 , 7.5.1.5.4 , 7.5.2.2.3 , and T able 7.5-1, item 10. Columbia Generating Station concurs with the intent of this position. The existing monitors are redundant and provide continuous display and redundant recording in the control room. The instruments are seismically and en vironmentally qualified to Class 1 requirements with a range C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-24 of 0-30% hydrogen concentra tion. A complete design description is provided in Section 6.2.5.2. The accuracy of this instrument is Instrument accuracy (loop) = +/-0.2% H 2 in the range 2-6 H 2 and +/-2.0% for remainder of full scale

II.F.2 INSTRUMENTATION FOR DETECTIO N OF INADEQUATE CORE COOLING

Position Licensees shall provide a descrip tion of any additional instrumenta tion or controls (primary or backup) proposed for the plant to supplemen t existing instrumentation (including primary coolant saturation monitors) in order to provide an unambiguous, easy-t o-interpret indication of inadequate core cool ing (ICC). A description of the f unctional design requirements for the system shall also be included.

A description of the procedures to be used with the proposed equipment, the analysis used in developing these procedures, and a schedule for installing the equipment shall be provided (NUREG-0737).

Clarification

None.

Columbia Generating Station Position

CGS actively participated in the efforts of the BWR Owner's Group (BWROG) and the Licensing Review Group (LRG) to develop an industry understanding of NRC's concerns and an approach to detect i nadequate core cooling.

An analysis of in-core ther mocouples, as proposed in recen tly published Safety Evaluation Reports applicable to BWRs, led the BWROG, LRG, and CGS to conc lude that in-core thermocouples did not serve as effective instruments for detec tion of inadequat e core cooling and did not substantially improve th e safety of the plant. The tw o major deficiencies of incore thermocouples are inadequate (i.e

., long) response time and potentia lly erroneous indications.

In addition, a risk assessment of the effect on the addition of in-core thermocouples has concluded that even if in-core th ermocouples were arbi trarily assumed to provide an effective backup to the plant water level detectors, overall plant risk would not be significantly reduced.

Based on this risk analysis, in-cor e thermocouples were not considered to be a cost effective modification for CGS. The results of the abo ve studies were presente d to the NRC by the BWROG and LRG executives in a meeti ng in Bethesda on December 17, 1981.

C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-25 In Operating License NF-21 i ssued December 19, 1983 the sta ff conditioned the license to "implement the staff's require ments regarding additional instru mentation for detection of inadequate core cooling which may result from the staff's review of the BWR Owner's Group reports (SLI 8211 and SLI 8218)...." Generic Letter 84-23 comprised the staff's review and requested additional information. The Energy Northwest response to Generic Letter 84-23, Letter GO2-84-617 dated November 27, 1984, satisfied the licensing condition and closed this issue.

II.K.1.5 Assurance of Proper Engi neered Safety Feature Functioning Position Review all valve positions, positioning requireme nts, positive controls , and related test and maintenance procedures to ensure proper engineered safety fe ature (ESF) functioning. See NRC Bulletins79-06A Item 8, 79-06 B Item 7, and 79-08 Item 6.

This requirement shall be met before fuel loading.

Clarification None. Columbia Generating Station Position This italicized information is historical and was provided to support the application for an operating license. The FSAR disc u sses this topic in Sectio n s 7.1.2.4 , 7.3.1.1 , 7.3.2.1.2 , 7.3.2.1.3 , and A ppendix B,Section I.C.6. Directives on valve positioning requiremen ts, positive controls, and test and maintenance procedures associated with ESF systems have been prepared. Mo tor-operated valves in safety systems are normally maintained in a configuration such as to require the least number of valve automatic movements on system actuation. System initiation logic is such that valves automatically move to the required position when required. The position of vital manual ECCS valves is controlled by the use of and documentation of locks on valve handwheels. In addition, numerous vital manual valves have pos ition status indicating lights in the control room. Columbia Generating Station is equipped with ESF system status displays, which continuously monitor the ESF systems and pr ovide indication to the opera tor of a system bypass or inoperability introduced during testing or maintenance which renders the system(s) unable to respond to an initiation signal. Typical par ameters monitored include the following:

a. Valve position, C OLUMBIA G ENERATING S TATION Amendment 55 F INAL S AFETY A NALYSIS R EPORT May 2001 LDC N-0 0-0 1 8 B.2-26 b. Power available to motor-operated valves, c. Initiation logic power available, d. Power sources (including emergency diesels) available, and e. Breaker status.

Alarms are provided on a syst em level basis. Indication is provided on a component level basis. Surveillance and testing pro cedures for ESF systems will include checks to ensure the system is returned to standby status on completion of testing.

When ESF equipment is removed from service for maintenance, procedures require documentation of removal and return to service.

Functional tests of equipment returned to service following maintenance are required by these procedures to ensure operability.

NUREG-0892, the WNP-2 Safety Evaluation Report, discussed this issue and listed confirmation of procedures as confirmatory issue No. 22. En ergy Northwest letter GO2-83-247 dated March 23, 1983, "Confirma tory Issue No. 22, Assurance of ESF Functioning (II.K.1.5) and Safety-Related System Operability Status (II.K.1.10)," satisfi ed the confirma tory issue, subsequently listed as resolved in Supplement 4 to NUREG-0892.

II.K.1.22 Proper Functioning of Heat Removal Systems Position Describe the actions, both aut omatic and manual, necessary for proper functioning of the auxiliary heat removal systems (e.g., RCIC) that are used when the main feedwater system is not operable. For any manual action necessary, describe in su mmary form the procedure by which this action is taken in a timely sense. (IE Bulletin 79-08).

Clarification None. Columbia Generating Station Position This italicized information is historical and was provided to support the application for an operating license. The FSAR conta i ns information regarding RCIC operation in Sections 5.4.6 and 7.4.1.1; information regard i ng HPCS is contained in 6.3.2.2.1 and 7.3.1.1.1.1. RHR information is contained in S ections 5.4.7.1.1 , 6.2.2 and 7.3.1.1.5 (s uppression pool cooling mode) and 5.4.7.1.5 and 5.4.7.2.6 (shu t down cooling mode).

Energy Northwest letter GO2 107, dated May 23, 1980, res ponded to IE Bulletin 79-08. Additional information pertaining to the above requirement is provided below.

C OLUMBIA G ENERATING S TATION Amendment55 F INAL S AFETY A NALYSIS R EPORT May2001 LDCN-00-018 B.2-27 Initial Core Cooling:

Following a loss of feedwater and re actor scram, a low reactor wate r level signal (level 2) will automatically initiate main steam line isolation valve closure. At the same time this signal will put the HPCS and RCIC systems into the reactor coolant ma keup injection mode. These systems will continue to inject water into the vessel until a hi gh water level signal (level 8) automatically trips RCIC and closes the HPCS injection valve. Th e HPCS pump remains running on minimu m flow bypass.

Following a high reactor water level 8 trip, the HPCS injection valve will automatically reopen when reactor water level decrease s to low water level 2. The RCIC system will automatically reinitiate after a high water leve l 8 trip when reactor water level decreases to low water level trip 2. The HPCS and RCIC systems ha ve redundant supplies of water.

Normally they take suction from the condensate storage tank (CST).

The HPCS and RCIC sy stems suctions will automatically transfer from the CST to the suppression pool if the CST water is depleted or, for the HPCS system, the suppression pool water level incr eases to a high level.

The RCIC system will start autom atically on receipt of a low wa ter level (level

2) initiation signal. On receipt of this initiation signal, the following events occur simultaneously unless otherwise noted:

a. Test bypass valves to condensate storage tank closes (if open);

b. Steam supply valve to turbine opens;

c. Pump discharge injecti on valve opens when the turb ine steam supply valve is open; d. Gland seal system starts;

e. Cooling water supply valve to lube oil cooler opens;

f. Pump suction valve from condens ate storage tank opens (if closed);

g. The turbine control system brings the turbine up to speed as soon as the steam supply valve leaves its full closed positi on. Pump discharge flow develops as soon as the pump discharge pressure is sufficient to open the check valve between the pump and the re actor vessel. As pump discharge and steam inlet pressure change with a variable reactor pressure range, the control signal will be sent to the turbine to maintain constant st eady state pump flow; and C OLUMBIA G ENERATING S TATION Amendment59 F INAL S AFETY A NALYSIS R EPORT December2007 LDCN-04-027 B.2-28

h. When pump discharge pre ssure reaches a predetermi ned pressure, the minimum flow valve opens until system flow reac hes a predetermined flow, then it will close.

RCIC flow may be directed away from the vessel by diverting the pump discharge to the CST.

This is accomplished by closi ng injection valve RCIC-V-13 and opening the test return valves (RCIC-V-22 and 59). The system is returned to injection mode by closing RCIC-V-59 and then opening RCIC-V-13. This mode of operation will not be used during events where an unacceptable source term is identified in primary containment. Diverting RCIC flow to the CST is not a safety-related function nor does this mode affect the ability of RCIC to initiate during plant transients. The system automatically switches to injection m ode if the water level decreases to the low level initiation point (Level 2).

The HPCS system will start automatically upon receipt of a low wa ter level (level 2) initiation signal. Upon receipt of this initiation signal, the following events occu r simultaneously unless otherwise noted:

a. High-pressure core spray diesel generator starts;

b. High-pressure core spray pump starts;

c. High-pressure core sp ray suction valve and HPCS injection valve open;

d. Condensate storage tank and suppression pool test re turn and bypass valves close (if open);

e. Minimum flow bypass valve automatical ly opens if HPCS pump is delivering pressure and system flow is low. Minimum flow bypass valve automatically closes when the flow rate from the pump reaches a predetermined flow;

f. High-pressure core spray service water pumps starts; and

g. High-pressure core spra y room cooler fan starts.

The operator can manually initiate the HPCS and RCIC systems from the control room before the level 2 automatic initiation level is reached.

The operator has the op tion of manual control after automatic initiation. The operator can verify that these systems are delivering water to the reactor vessel by

a. Verifying reactor water level increases when systems initiate,

b. Verifying systems flow using flow indicators in the control room, and C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 0-0 1 8 B.2-29 c. Verifying system flow is to the re actor by checking control room position indication of motor-operated valves. This ensures no diversion of system flow to other than the reactor.

Therefore, the HPCS and RCIC can maintain reactor water leve l at full reactor pressure and until pressure decreases to where low pressure systems such as the LPCS of LPCI can maintain water level.

Containment Cooling:

After reactor scram and isolati on and establishment of satisfact ory core cooling, the operator would start containment cooling. This mode of operation remo ves heat resulting from SRV discharge to the suppression pool.

This would be accomplished by placing the RHR system in the containment/suppression pool cooling mode, or the suppres sion pool spray mode, i.e., RHR suction from and discharge to the suppression pool. A summary of th e operator actions is given in the following:

a. Start the associated RHR standby se rvice water (SW) pump, if not already running, b. Open the SW pump discharge valve, if not already open, c. Open the SW loop return valve, if not already open, d. Start the associated RHR pump, e. Close the associated RHR heat exchanger bypass valve, f. Adjust system flow by adjusting the RH R test return valve if in the suppression pool cooling mode, and

g. Open the suppression pool spra y valve if in the spray mode.

The Operator could verify proper operation of the RHR system containment cooling function from the control room by the following:

a. Verifying RHR and SW sy stem flow using system cont rol room flow indicators, b. Verifying correct RHR and SW system flow paths using control room position indication of motor-operated valves, and

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 0-0 1 8 B.2-30 c. On branch lines that could divert flow from the required flow paths, closing the motor-operated valves and noting th e effect on RHR and SW flow rate.

Extended Core Cooling:

When the reactor has been depressurized, the RHR system can be placed in the long-term shutdown cooling mode. The opera tor manually terminates the containment cooling mode of one of the RHR loops and places the loop in the shutdown cooli ng mode as follows:

a. Trip the RHR pump to be used for shutdown cooling, b. Close associated motor-operated val ve in the suppression pool suction and LPCI discharge line to the vessel, c. Open shutdown cooling su ction valves from and dischar ge valves to the reactor vessel, and

d. Restart the RHR pump.

In this operating mode, the RHR system can cool the reactor to cold shutdown. Proper operation and flow paths in this mode can be ver ified by methods similar to those described for the containment cooling mode.

In conclusion, the plant design is fully adequate to meet the in tent of the requirements of auxiliary heat removal when th e main system is inoperable.

II.K.1.23 Reactor Vessel Level Instrumentation Position Describe all uses and types of vessel level indication for both automatic and manual initiation of safety systems. Describe other redundant instru mentation which the ope rator might have to give the same information regarding plant status. Instruct operators to utilize other available information to initiate safety systems (IE Bulletin 79-08).

Clarification None. Columbia Generating Station Position This italicized information is historical and was provided to support the application for an operating license. The FSAR contains desc riptions for the Reactor Vessel Level C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 0-0 1 8 B.2-31 Instrumentation and the design basis of the Safety Related Display Instrumentation in the following sections:

7.5.1.1.1 , 7.7.1.1.2.2 , 7.7.1.4.2.1 , 7.5.2 , and T ab l e 7.5-1. NEDO-24708 describes the multiple water level instrumentation provided in the BWR control room for the operator. An outlin e of the specific indication for Columbia Generating Station is provided in the following paragraphs, which full y meets the intent of the plant requirements and the NRC requirements.

Reactor vessel water level is continuously monitored by four recorders for normal, transient, and accident conditions. These four instruments are divided into two divisions of two instruments each to provide an overlapping range from above the maximum operating level to below the active core. Thus, ade quate information is provided to the operator for manual initiation of safety actions and for assuran ce of the vessel water level at all times.

Those sensors used to provide automatic sa fety equipment initiation are arranged in a four-quadrant vessel tap configura tion with the four sensors di vided electricall y between two divisions.

In addition, the operating procedur es will reflect the requirements for the operators to also rely on the information provided by other plant parameter indications relating to vessel level.

A separate set (to that describe d above) of range level instrume ntation provides reactor level control via the reactor feedwater system. This set also indica tes or records in the control room. Additionally, an upset range (0-180 in.)

and a shutdown range (0

-400 in.) are provided for operator information.

The safety-related systems or functions served by safety-related reactor water level instrumentation are the following:

RCIC HPCS LPCS RHR/LPCI ADS Nuclear steam supply shutoff system (NSSSS) Reactor protection system (RPS) Standby gas treatment system (SGTS) Emergency power system Secondary containment isolation Main control room and critical switchgear HVAC Standby service water system Containment instrument air system Trip of nonessential loads C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 0-0 1 8 B.2-32 Low reactor vessel water level is used in the initiation logi c of all systems listed above. In addition, the RCIC and HPCS systems shut down on high reactor vessel water level. HPCS and RCIC will automatically restart if low reactor level is agai n reached (see response to TMI Items II.K.1.22 and II.K.3.13, re spectively, for further disc u ssion). Additional information about reactor vessel level instr u mentation is also provided in Section 5.2 and in Figure 3.6-1. This position has been accepte d in the NRC Safety Evaluati on Report, NUREG-0892, dated March 1982, section 7.5.2.1.

II.K.3.21 Restart of Core Spray and Low Pressure Coolant Injection Systems

Position The core spray and low pressure coolant injection (LPCI) system flow may be stopped by the operator. These systems will not restart automat ically on loss of water level if an initiation signal is still present. The core spray and LPCI system logic should be modified so that these systems will restart, if require d, to assure adequate core co oling. Because this design modification affects several co re cooling modes under accident conditions, a preliminary design should be submitted for staff review and approval prior to making the actual modification.

Clarification

Modification of system design should be made in accordance with those requirements set forth in Sections 4.12, 4.13, and 4.16 of IEEE Standard 279-1971 with regard to protective function bypasses and completion of prot ective action once initiated.

Columbia Generating Station Position

CGS as a participant in the BWR Owner's Grou p endorses the position pres ented in the letter dated December 29, 1980, from D. B. Waters to the NRC (attention D. G. Eisenhut),

Subject:

"BWR Owner's Group Evaluation of NUREG-0737 Requirements."

The position presented in enclosure 2 to this letter c oncludes that the current system design is adequate and no design changes are required. CGS concurs in this position.

It should be noted that this design allows the operator to evaluate the plant and avoid an automatic restart that may have an adverse impact on the situation.

This position has been accepte d in the NRC Safety Evaluati on Report NUREG-0892, dated December 1982, section 7.3.2.1.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 B.2-33 II.K.3.25 Effect of Loss of Alterna ting-Current Power on Pump Seals Position The licensees should determine, on a plant-specific basis, by analysis or experiment, the consequences of a loss of cooli ng water to the reactor recirculation pump seal coolers. The pump seals should be designed to withstand a comple te loss of alternating-current (ac) power for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Adequacy of th e seal design shoul d be demonstrated.

Clarification The intent of this position is to prevent excessive loss of reactor coolant system (RCS) inventory following an anticipated operational occurrence. Loss of ac power fo r this case is construed to be loss of offsite power. If seal failure is the consequence of loss of cooling water to the reactor coolant pump (RCP) seal coolers for 2 hr, due to loss of offsite power, one acceptable solution would be to supply emergency power to the component coolin g water pump. This topic is addressed for Babcock and Wilcox (B&W) reactors in Item II.K.2.16.

Columbia Generating Station Position

Columbia Generating Station, as a participant in the BW R Owners' Group, endorses the position developed by General Electric for the Owners' Grou

p. This position has been transmitted in a letter from the BWR Owners' Gr oup to the NRC, T. J. Dente to Darrell G. Eisenhut, dated September 21, 1981. In this supplement to the BWR Owners' Group evaluation of NUREG-0737, Item II.K.3.25, Genera l Electric presented te st data from a test performed at the Bingham Pump Company's test facility in 1973 on the CGS recirculation pump. During the operability testing of the pump at rated temperature and pressure the seal cavity was deprived of seal pur ge and the external heat exchanger was deprived of coolant. As a result, the seal cavity temp erature exceeded 270°F. Test pe rsonnel visually monitored pump leakage for more than five hou rs and observed no leakage beyond the capability of the 1-in.

seal drain lines, less than 5 gpm. These test results provide confirmation that loss of cooling to the Bingham pump seal for 5 hr does not lead to unacceptable seal leakage. This loss is easily compensated for by normal water level controls and presents no ha zard to the health and safety of the public.

This position has been accepte d in the NRC Safety Evaluati on Report NUREG-0892, dated December 1982, section 15.1.2.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 B.2-34 II.K.3.44 Adequate Core Cooling fo r Transients with a Single Failure Position For anticipated transients combin ed with the worst single fail ure and assuming proper operator actions, licensees should demonstrate that the core remains covered or provide analysis to show that no significant fuel damage results from core uncovery.

Transients which result in a stuck-open relief valve should be incl uded in this category (NUREG-0737).

Clarification None.

Columbia Generating Station Position

CGS as a member of the BWR Owners' Group endorses the following position statement and analysis prepared by GE on behalf of the Owners' Group:

==

Introduction:==

This report has been prepared as the BWR Owners' Group ge neric response to NUREG-0737 Task Item II.K.3.44 which addre sses the issue of adequate core cooling for transients with a single failure for those plants identified in Table II.K.3.44-4.

At the outset it should be noted t hat the conditions described in II.K.3.44 (i.e., transients plus single failures) go beyond the current BWR de sign basis and that the item's reference to transients with multiple failure s goes beyond the regulatory requirements as specified in Regulatory Guide 1.70, Revision 3. The multiple failures specified invol ve consideration of a stuck-open relief valve (SORV) combined with the worst single failure. GE and the Owners' Group continues to support the cu rrent BWR design basis approach. This report is intended to provide information to address I t em II.K.3.44 , b u t does not ref l e c t our i n tention to change the current BWR design basis approach.

It is shown that, for the GE BWR/2 through BWR/6 plants, the core remains covered for any transient with the worst single failure. This is achieved without any operator action to manually initiate ECCS or other inventory makeup systems. The worst transient with the worst single failure is shown to be the loss of f eedwater (LOF) event with a failure of the high pressure ECCS or one is olation condenser (IC) loop, whichever is applicable.

For the bounding LOF event, studies which included even more degraded conditions have been documented in Reference

1. T h e degraded conditions cover the f a ilure of HPCS (or HPCI or FWCI or IC) and one SORV. Reference 1 sho w s that the core will remain covered and therefore that no fuel failure would occur.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 B.2-35 Criteria, Scope and Assumptions:

NUREG-0737 Item II.K.3.44 requires that the licensees demonstrate adequate core cooling to prevent the fuel from incurring significant damage for the anticipated transi ents combined with the worst single failure. To meet this requirement, either one of the following two criteria should be satisfied:

a. The reactor core rema ins covered with water until stable conditions are achieved, or

b. No significant fuel damage results from core uncovery.

For BWR plants, this report will show that Criterion 1 is met. The report makes the following

assumptions:

a. A representative plant of each BWR product line, BWR/2 through BWR/6, is used to represent all of the plants of that product line,

b. The anticipated transients as identified in NRC Regulatory Guide 1.70, Revision 3 were considered,

c. The single failure is interp reted as an active failure, and

d. All plant systems and components are assumed to function normally, unless identified as being failed.

Discussion:

Table II.K.3.44-1 lists all of the transients which were considered in this study. The event sequence of each transient was examined for each product line to determine the impact on core cooling. The following three factors were used to determine the worst transient and the worst single failure:

a. Reduction or loss of main feedwater or coolant makeup or heat removal systems, especially high pressure systems, e.g., HPCI, feedwater coolant injection (FWCI), HPCS, RCIC or isolation condenser (IC),

b. Steam release paths causing rapid reactor coolant in ventory loss, e.g., SRVs, turbine, or turbin e bypass valves, and

c. Power level, especia lly the timing of scram.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 B.2-36 Based on these considerations, a comparison was made among the transients in Table II.K.3.44-1. In Refe r e nce 2 , the even t s of Table II.K.3.44-1 are compared in detail for a typical BWR/4 plant. In particular the impact on core cooling for each transi ent is evaluated by comparison to the analysis results fo r the LOF event in the s ection titled "Applicability of Analyses." It is found that the LOF event is the most se vere transient from the core cooling viewpoint due to its rapid depletion of reactor coolant inventory. This conclu sion has generic applicability to all BWR product lines covered by this study.

The same approach was also used to select th e single failures which would pose the greatest challenge to core cooling. Among all of the possible failures considered (Table II.K.3.44-2 the following failures are identified as the most important ones:

a. Failure of HPCI or HPCS or FWCI or one IC loop, whichever is applicable, b. Failure of RCIC, and

c. One of the SRVs, which has opened as a result of the transient, fails to close.

Items a and b are the possible lim iting failures because they re present loss of high pressure inventory makeup or heat removal systems which would be relied on following a loss of feedwater event. Item c is a possible limiting failure, bec ause it results in the largest steam release rate from the vessel compared to other possible re lease paths (e.g., a stuck-open turbine bypass valve). No other failures identified in Table II.K.3.44-2 result in a direct challenge to core cooling capability.

Because of the relatively low steam loss capacity through one SO RV (Item c) compared to the makeup water capacity of the highest capacity makeup water system , the failure of the highest capacity high pressure ma keup system (Item a) would be wo rse than a stuck-open relief valve (Item c). For example, for a ty pical BWR/4, representative values of HPCI makeup and SRV flow are 18% and 6% of rated fe edwater flow, respec tively. Because of the higher makeup rate of HPCI/HPCS relative to RCIC (3% of rated feedwater flow), Item a would be worse than Item b. Table II.K.3.44-3 lists the worst combination of transient and single failure for the GE BWR product lines covered by this study.

Even with the worst single failure in combination with the LOF event, the RCIC or at least one IC loop will function to provide makeup and/or to remove decay he at while the vessel pressure remains high. The design basis for the RCIC or the IC is such that they are capable of removing decay heat with the vessel being isolated. Analyses of the LOF event with the worst single failure have been performed to support this conclusion. For example, for BWR/2 plants, such analyses are documented in R e ference 1 , Table 3.2.

1.1.5-5. These analy s es show that the

isolation condenser heat remova l capacity is greater than the d ecay heat generation rate and will lead to a safe and stable condition.

Similar analysis have been performed for representative plants with the RC IC system. These analyses show that for the worst transient C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 B.2-37 with the worst single failure, the minimum water level for diffe rent BWR product lines ranges from 6 ft to 11 ft above the top of the active fuel.

With even more degraded conditions, i.e., one SORV in addition to the worst case transient with the worst single failure, reference plant analys e s in Reference 1 , T a bles 3.2.1.1.5-9 and

3.2.1.1.5-10 show that for the plants analyzed the RCIC system can automatically provide sufficient inventory to k eep the core covered even with a single failure plus a SORV. This capability is not a design basis for the RCIC system, and not all plants have been analyzed to demonstrate this capability. If a plant should not have this capability, manual depressurization will avoid core uncovery for the case of LOF plus worst single failure plus SORV. It should be noted that manual depressurization is the pr oper operator action for all plants during loss of inventory conditions when th e high pressure cooling syst em(s), are unable to restore and maintain RPV level. These proper operator actions are allowed for in the NUREG-0737 requirement.

For plants without RCIC, manual depressurizati on will avoid core unco very for the case of LOF plus worst single failure plus SORV.

==

Conclusion:==

The anticipated transients in NRC Regulatory Gu ide 1.70, Revision 3, were reviewed for all BWR product lines BWR/2 through BWR/6 from a core cooling viewpoint. The LOF event was

identified to be the most limiting transient which would challenge core cooling. The BWR is designed so that the high pressu re makeup or inventory maintenance systems or heat removal systems (HPCI, HPCS, FWCI, RCIC or IC) ar e independently capable of maintaining the water level above the top of the active fuel given a loss of feed water. The detailed analyses show that even with the worst single failure in combination with th e LOP event, the core remains covered.

Furthermore, even with more degraded conditions invo lving one SORV in addition to the worst transient with the worst single failure, studies show that the core remains covered during the whole course of the transient either due to RCIC operation or due to manual depressurization.

This position has been accepte d in the NRC Safety Evaluati on Report NUREG-0892, dated December 1982, section 15.1.2.

References:

1. Section 3.2.1 (prepublication form) of "A dditional Information Re quired for NRC Staff Generic Report on Boiling Water Reac tors," NEDO-24708, March 31, 1980.

2. Section 3.2.2 (prepublication form) of "A dditional Information Re quired for NRC Staff Generic Report on Boiling Water Reactors," NEDO-24708, June 30, 1980.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 B.2-38 3. Section 3.5.2.1 (prepublication form) of "Additional Information Required for NRC Staff Generic Report on Boiling Water Reactors," NEDO-24708, August 31, 1979.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-39 Table II.K.3.44-1 Summary of Initiating Transients

(

Reference:

NRC Regulato r y Guide 1.70, Revision 3)

1. Loss of feedwater heating 2. Feedwater controller fa ilure - maximum demand 3. Pressure regulat or failure - open 4. Inadvertent safety

/relief valve opening 5. Inadvertent residual heat removal (RHR) shut down cooling operation 6. Pressure regulator failure - closed 7. Generator load rejection

8. Turbine trip 9. Main steam isolati on valve (MSIV) closure 10. Loss of condenser vacuum 11. Loss of normal ac power

12. Loss of feedwater flow 13. Failure of RHR shutdown cooling 14. Recirculation pump trip

15. Recirculation flow control failure - decreasing flow 16. Rod withdrawal error

17. Abnormal startup of idle recirculation pump 18. Recirculation flow contro l failure - increasing flow 19. Fuel loading error 20. Inadvertent start up of high pressure core spray (HPCS) or high pr essure coolant injection (HPCI) or feedwater coolant inj ection (FWCI) or isolation condenser (IC), whichever is applicable.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-40 Table II.K.

3.44-2 List of Single Failures Whi c h Can Potentially Degrade the Course of a BWR Trans i e nt

1. One or all of the bypass valves fail to modulate open when required. 2. One of the bypass valves, which has opene d as a result of the transient, fails to close. 3. Failure to trip the turbine or feedwater pumps on high water level. 4. One main steam isolation valve (MSIV) fails to close when required. 5. One of the safety/relief valves fails to open when required. 6. One of the safety/relief valves, which has opened as a result of the transient, fails to close. 7. Failure to trip one recirculation pump. 8. Failure to run back the recirculation pumps.

9. Failure of high pressure coolant injection (HPCI) or high pressure core spray (HPCS) or feedwater coolant injection (FWCI) or one isol ation condenser (IC) loop, whichever is applicable. 10. Failure of reactor core isolation cooling (RCIC) or one IC loop, whichever is applicable. 11. Failure of one low pressure coolant injection (LPCI) loop or the low pressure core spray (LPCS) system. 12. Loss of one residual heat removal (RHR) system heat exchanger. 13. A single control rod stuck while the re mainder of the control rods are moving. 14. Failure to achieve the r od block function (i.e., a singl e control rod will withdraw upon erroneous withdrawal demand). 15. Loss of one diesel generator if loss of ac power was the initiating event.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-41 Table II.K.

3.44-3 Worst Case of Transient with a Single Failure f o r Different BWR Product Lines

Product Line Transient with a Single Failure (Worst Case)

BWR/2 LOF + Failure of one IC loop (Oyster Creek only)

LOF + Failure of FWCI (Nine Mile Point only)

BWR/3 LOF + Failure of FWCI (Millstone only)

LOF + Failure of HPCI (others)

BWR/4 LOF + Failure of HPCI BWR/5 LOF + Failure of HPCS BWR/6 LOF + Failure of HPCS 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 B.2-42 Table II.K.

3.44-4 Participating Utilitie s a NUREG-0737 Boston E d ison Pilgrim 1 Caroline Power & Light Brunswick 1 and 2 Commonwealth Edison LaSalle 1 and 2, Dresden 1-3, Quad Cities 1 and 2 Georgia Power Hatch 1 and 2 Iowa Electric Light & Power Duane Arnold Jersey Central Power & Light Oyster Creek 1 Niagara Mohawk Power Nine Mile Point 1 and 2 Nebraska Public Power District Cooper Northeast Utilities Millstone 1 Philadelphia Electric Peach Botto m 2 and 3; Li merick 1 and 2 Power Authority of the State of New York FitzPatrick Tennessee Valley Authority Browns Ferry 1-3; Hartsville 1-4, Phipps Bend 1 and 2 Vermont Yankee Nuclear Power Vermont Yankee Detroit Edison Enrico Fermi 2 Mississippi Power & Li ght Grand Gulf 1 and 2 Pennsylvania Power & Li ght Susquehanna 1 and 2 Energy Northwest Columbia Generating Station Cleveland Electric Illuminating Perry 1 and 2 Houston Lighting & Power Allens Creek Illinois Power Clinton Station 1 and 2 Public Service of Oklahoma Black Fox 1 and 2 Long Island Lighting Shoreham a Report applies to plants in cluded herein whose owners participated in the report development.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-43 II.K.3.45 Evaluation of Depressurization w ith Other than Automatic Depressurization System Position Analyses to support depressurization modes other than full actuation of the ADS (e.g., early blowdown with one or two SRVs) should be provided. Slower depressurization would reduce the possibility of exceedi ng vessel integrity limits by rapid cooldown (NUREG-0737).

Clarification None.

Columbia Generating Station Position

CGS as a member of the BWR Owners' Group endorses the following position statement and analysis prepared by GE on behalf of the Owners' Group.

The evaluation of alternate modes of depressuri zation other than full actuation of the Automatic Depressurization System (ADS) is made for those plants listed in Table II.K.3.45-5 with regard to the effect of such reduced depressurization rates on core cooling and vessel integrity.

Depressurization by full ADS act uation constitutes a depr essurization from about 1050 psig to 180 psig in approximately 3.3 minutes. Such an event, which is not expected to occur more than once in the lifetime of the pl ant, is well within the design basis of the reactor pressure vessel. This conclusion is based on th e analysis of severa l transients requiring depressurization via the ADS val ves. Results of these analyses indicate that the total vessel fatigue usage is less t han 1.0. Therefore, no change in the depressurization rate is necessary.

However, to comply with the above request reduced depressuri zation rates were analyzed and compared with the full ADS actuation. The a lternate modes considered cause vessel pressure to traverse the same pressure range in (1) depressurization case 1 (ranges from 6-10 minutes depending on plant size and ADS capacity), and (2) depressurizati on case 2 (ranges from 15-20 minutes). The case 2 depressurization bounds the possible increase in depressurization

time by producing an undesirabl y long core uncovered time. Th e case 1 depressurization gives the results of an intermediate depressurization. These m odes are achieve d by opening a reduced number of relief valves. Thes e blowdown rates are illustrated by Figure II.K.3.45-1.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-44 Assumptions:

The major assumptions used for the core cooling analysis are as follows:

a. No high pressure coo ling systems are available,

b. All low pressure E CCS is available, and

c. Assumptions as stated in NEDO-24708, Section 3.

1.1.3, "Justification of Analysis Methods," which includes the use of 1978 ANS Decay Heat (mean value).

Results:

a. Vessel Integrity

The depressurization events considered are full ADS blowdown and blowdown over 10 and 20 minute intervals. The reac tor vessel stresses for these events are within the acceptance stress limits defined by ASME Code Section III for emergency conditions (Level C). Th e core support stru ctures and other safety-related internal components are also within applicable emergency condition stress limits.

The ADS operating conditions which affect fatigue us age of vessel or core support structures are not significantly different for fast and slow blowdown events. Specific calculations of fatigue usage are not required for emergency conditions (Level C). However, available pressure vessel fatigue analyses show the usage per event to be <0.1 per full ADS event.

In summary, reactor vessel and core suppor t structure integrity is assured for

the blowdown rates considered if an AD S event should occur, and reduced rates of depressurization do not significantly decrease fatigue usage.

b. Core Cooling Capability Examination of the reduced depressuri zation rates under consideration with respect to core cooli ng concerns shows that:

1. Vessel depressurization for a case 2 blowdown (15-20 minutes) causes the core to be uncovered for a le ngthy period of time even assuming system initiation at the earliest reasonable time.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-45 2. Vessel depressurization for a case 1 blowdown (6-10 minutes), when actuated at the same level as the full ADS case, will result in less vessel inventory at the time of ECCS injection an d can result in longer periods of core uncovery.

3. Vessel depressurization for a case 1 blowdown (6-10 minutes) when actuated considerably ea rlier than at the ADS initiation setpoint can result in some improvemen t in core cooling. However, the operator is required to act more quickly in these ca ses (i.e., within 1-6 minutes after the accident). This earlier depr essurization also reduces the time available to start high pressure syst em injection and hence to avoid the need for manual depressurization. It also increases the frequency of depressurization.

The results of the calcul ations are presented in Tables II.K.3.45-1 through II.K.3.45-4. They show the total core uncovered time and remaining vessel inventory at the time of low pressure ECCS injection. A discussion of these results follows below.

Discussion:

The results are based upon calculat ions performed with the assump tions stated earlier using a representative BWR/3 and a BWR/6 to show consistency of resu lts across the product lines.

The transients considered are an outside steam li ne break and a stuck-open relief valve. The ADS will depressurize the vessel to the low pres sure ECCS injection setpoint when no high pressure cooling systems are available. The depressurizations used are initiated at different times based on the downcomer wate r level. The first initiation time considered is when the water level is at the top of the active fuel which is consistent with the or iginal design for most plants and thus is the basis fo r comparison. The second initia tion time considered is the downcomer water level of 34 feet from the bottom of the vessel wh ich still provides the operator with a reasonable time to attempt to start the hi gh pressure systems. The last initiation time considered is the high pressure makeup system setpoint (Level 2 for BWR/6 and Level 1 for BWR/3) plus 60 seconds which is the earliest time in which de pressurizaton c ould be expected to occur.

The core cooling criteria used in assessing the impact of a redu ced depressurization rate are:

a. Inventory in the core and lower ple num at the time of low pressure ECCS injection as predicted by t h e SAFE m odel (Reference 1), and

b. The total time which the top of the active fuel (TAF) remains uncovered as predicted by the SAFE m odel (Reference 1).

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-46 The first criterion demonstrates the increased mass loss due to boiloff for the longer blowdown, since mass loss due to flashing will be independ ent of the depressuriza tion rate providing the boundary pressure values are the sa me for all the rates.

The second criteri on is a measure of the resultant core temperature.

Table II.K.3.45-1 gives the results for a BWR/6 assuming an outside steam line break. As the length of depressurization is increased the vessel inventory at the time the ECCS injection decreases and the total core uncovered time increases.

Table II.K.3.45-1 further shows that the actuation times based on higher water levels (i.e., 34 ft and Level 2 +60 sec) longer depressurizations exhibit the same trends. Fu rthermore, for any partic ular depressurization rate, raising the actuation level increases the vessel inventory at ECCS injection and decreases the total core uncovered time. However, this also decreases the time the operator has available to try to get high pressure level control systems working in order to avoid the need to depressurize.

Table II.K.3.45-2 shows that these same results are exhib ited for the case of a stuck-open relief valve. Table II.K.3.45-3 shows the results for a BWR/3 assumi ng an outside steam line break.

Examination of the table s hows the same trends as Table II.K.3.45-1 , and therefore the results are applicable to all product lines. Table II.K.3.45-4 shows that these general trends are independent of the models us ed by exhibiting the same tr ends for a BWR/3 using standard Appendix K licensing assumptions.

==

Conclusion:==

The cases considered show t hat no appreciable improvement can be gained by a slower depressurization based on core cooling consider ations. A significantly slower depressurization rate will result in increased core uncovered time. A moderate decrease in the depressurizaton rate necessitates an earlier act uation time resulting in less time available for operator action to start high pressure ECCS without significant benefit to vessel fa tigue usage. This will also result in an increased frequency of ADS actuation.

Finally, it is of paramount importance to note that the ADS is not a normal core cooling system; it is a backup fo r high pressure cooling systems (f eedwater, RCIC, HPCI/HPCS). If ADS operation is ever required in a BWR, it will be because core cooling is threatened. Since a full ADS blowdown is well within the design basis of the reactor pressure vessel and ADS is properly designed to mini mize the threat to core cooling, no change in the depressurization rate is necessary.

Reference:

1. NEDO-24708, "Additional Information Required for NRC Staff Generic Report on Boiling Water Reacto rs," August 1979.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-47 Table II.K.3.45-1 Results for BWR/6 Out s ide Steam Line Break

No High Pressure Systems Available

Depressurization Case Depressurization Initiation Level Time (sec)

Core Uncovered Time (sec)

Liquid Inventory in Core and L o wer Plenum at Low Pressure ECCS Injection (lb)

Full ADS TA F a 1086.0 26 1.603 x 1 0 5 Case 1 TAF 1086.0 117 1.528 x 1 0 5 Case 1 34' 610.6 10 1.779 x 1 0 5 Full ADS Level 2 b +60 sec 78.3 No uncovery 1.993 x 1 0 5 Case 1 Level 2

+60 sec 78.3 No uncovery 1.937 x 1 0 5 Case 2 Level 2 78.3 390 1.755 x 1 0 5 a Top of active fuel.

b High pressure initiati o n se tpoint plus 60 sec.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-48 Table II.K.

3.45-2 Results for BWR/6 Stu c k-Open Relief Valve

No High Pressure Systems Available

Depressurization Case Depressurization Initiation Level Time (sec)

Core Uncovered Time (sec)

Liquid Inventory in Core and Lower Plenum at Low Pressure ECCS Injection (lb)

Full ADS TAF a 642.6 No uncovery 1.836 x 10 5 Case 1 TAF 642.6 15 1.787 x 10 5 Case 1 34' 391.8 No uncovery 1.889 x 1 0 5 Case 1 Level 2 b +60 sec 77.7 No uncovery 1.961 x 1 0 5 a Top of active fuel.

b High pressure initiation se tpoint plus 60 sec.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-49 Table II.K.3.45-3 Results for BWR/3 Out s ide Steam Line Break

No High Pressure Systems Available

Depressurization Case Depressurization Initiation Level Time (sec)

Core Uncovered Time (sec)

Liquid Inventory in Core and L o wer Plenum at Low Pressure ECCS Injection (lb)

Full ADS TA F a 1527.8 155 2.027 x 1 0 5 Case 1 TAF 1527.8 170 1.975 x 1 0 5 Case 1 34' 701.6 51 2.291 x 1 0 5 Full ADS Level 1 b +60 sec 364.4 No uncovery 2.446 x 1 0 5 Case 1 Level 1

+60 sec 364.4 10 2.394 x 1 0 5 a Top of active fuel.

b High pressure initiation setpoint plus 60 sec.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-50 Table II.K.

3.45-4 Results for BWR/3 Out s ide Steam Line Break

on A ppendix K Assumptions with No High Pressure Systems

Depressurization Case Depressurization Initiation Level Time (sec)

Core Uncovered Time (sec)

Liquid Inventory in Core and L o wer Plenum at Low Pressure ECCS Injection (lb)

Full ADS TA F a 759.4 264 1.960 x 1 0 5 Case 1 TAF 759.4 277 1.913 x 1 0 5 Full ADS Level l b +60 sec 145.6 175 2.210 x 10 5 Case 1 Level 1

+60 sec 145.6 191 2.165 x 10 5 a Top of active fuel.

b High pressure initiation se tpoint plus 60 sec.

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 B.2-51 Table II.K.

3.45-5 Participating Utilities a NUREG-0737

Boston E d ison Pilgrim 1 Caroline Power & Light Brunswick 1 and Commonwealth Edison LaSalle 1 and Dresden 2 and Q u ad Cities 1and 2 Georgia Power Hatch 1 and 2 Iowa Electric Light & Power Duane Arnold Jersey Central Power & Light Oyster Creek 1 Niagara Mohawk Power Nine Mile Point 1 and 2 Nebraska Public Power District Cooper Northeast Utilities Millstone 1 Northern States Power Monticello Philadelphia Electric Peach Botto m 2 and 3; Li merick 1 and 2 Power Authority of the State of New York FitzPatrick Tennessee Valley Authority Browns Ferry 1-3; Hartsville1-4, Phipps Bend 1 and 2 Vermont Yankee Nuclear Power Vermont Yankee Detroit Edison Enrico Fermi 2 Long Island Lighting Shoreham Mississippi Power & Light Grand Gulf 1 and 2 Pennsylvania Power & Li ght Susquehanna 1 and 2 Energy Northwest Columbia Generating Station Cleveland Electric Illuminating Perry 1 and 2 Houston Lighting & Power Allens Creek Illinois Power Clinton Station 1and 2 Public Service of Oklahoma Black Fox 1 and 2 a Report applies to plants in cluded herein whose owners participated in the report development.

C OLUMBIA G ENERATING S TATION Amendment 53 F INAL S AFETY A NALYSIS R EPORT November 1998 B.2-53 II.K.3.46 Response to List of Concerns from ACRS Consultant (Michelson Concerns)

Position General Electric should pr ovide a response to the Michelson c oncerns as they relate to BWRs.

See NURE G-0660, A ppendix C, Table c.3, Item 46 (Reference

1) and NUREG-0626, Section 4, Item A.17 (Reference 6c).

Clarification

None.

Columbia Generating Station Position

GE, acting for the BWR Owners' Group, responding to these concerns in a letter, "Response to Questions Posed by Mr. C. Mi chelson," R. H. Buchholz (G E) to D. F. Ross, dated February 21, 1980. Submittal of this letter completes the action required by this task.

This position has been accepte d in the NRC Safety Evaluati on Report NUREG-0892, dated December 1982, Section 6.3.6.

Vessel Blowdown Rates Used in Analysis 990578.72 II.K.3.45-1 Figure Form No. 960690Draw. No.Rev.Amendment 54 April 2000 0.0.4 0.8 1.2 1.6x10 3 1.2x10 1 0.8 0.4 0.Depressurization Pressure (PSIA)

Case (2)(15 - 20 min.)Time (Sec)

Depressurization

Case (1)

(6 - 10 min.)Full ADS (3.3 min.)

Columbia Generating StationFinal Safety Analysis Report C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 1-00A B.3-1 III.D.1.1 Primary Coolant Sources Outside Containment Position (Full Power License Requirement)

Applicants shall implement a program to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident to as-low-as-practical levels. This program shall include the following:

a. Immediate Leak Reduction

1. Implement all practical leak reduction measures for all systems that could carry radioactive fluid out side of containment.

2. Measure actual leakage rates with system in operation and report them to the NRC. b. Continuing Leak Reduction

1. Establish and implement a program of preventive maintenance to reduce leakage to as-low-as-practical levels. This program shall include periodic integrated leak tests at intervals not to exceed each refueling cycle.

Dated Requirement Applicants shall submit the information requested in the "Clarification" section of this position at least 4 months prior to issuance of a fuel-loading license.

This requirement shall be impl emented by applicants for operating license prior to issuance of a full-power license. See NUR EG-0737,Section III.D.1.1.

Clarification Applicants shall provide a summary description, together with initial leak-test results, of their program to reduce leakage from systems outside containment that would or could contain primary coolant or other highly radioactive fl uids or gases during or following a serious transient or accident.

a. Systems that should be l eak tested are as follows (any other plant system which has similar functions or postaccident characteristics even though not specified herein, should be included):

Residual heat removal (RHR),

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 1-00A B.3-2 Containment spray recirculation, High pressure injection recirculation, Containment and primary coolant sampling, Reactor core isolation cooling, Makeup and letdown (PWRs only), Waste gas (includes header s and cover gas system outside of containment in addition to decay or storage system).

Include a list of systems containing radioactive materials which are excluded from program and provide justification for exclusion.

b. Testing of gaseous systems should incl ude helium leak detection or equivalent testing methods.

c. Should consider program to reduce leak age potential release paths due to design and operator deficiencies as discussed in our letter to all operating nuclear power plants regarding North Anna and related incidents, dated Octobe r 17, 1979.

This requirement applies to a ll operating license applicants.

Columbia Generating Station Position Columbia Generating Station ha s performed a systems design review and established criteria for a surveillance/preve ntive maintenance program to limit to as-low-as-practic al, leakage from systems outside containment which could trans port highly radioactive fluids during a serious transient or accident.

a. Systems Review The systems for leak paths for primary coolant outside containment showed three potentially unisolated leak paths which c ould contain highly ra dioactive fluids during a serious accident or transient. These three leak paths originate at the reactor building sumps with a transport pathway to the waste collection tanks in the radwaste building. The three leak path lines ha ve been addressed in a licensing technical change. Dual auto-isolation valves have been added to each of the three lines along with accompanying isolation logic.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 0-0 1 8, 0 1-00A B.3-3 b. Leakage Monitoring A leakage surveillance and preventive maintenance program

• for those systems within secondary containment which could transport highly radioactive fluids in the case of a serious reactor transient or accident has the following features.

1. Designation of systems included within the leakage surveillance and preventive maintenance program:

(a) Residual Heat Removal, (b) Reactor Core Isolation Cooling, (c) High Pressure Core Spray, (d) Low Pressure Core Spray, (e) Primary Containment Atmospheric Control, (f) Primary Containment Atmospheric Monitoring, (g) Post Accident Sampling.

2. A system list which identifies the components to be in spected, the method of inspection or measurement, and the surveillance frequency.

3. Routine inspections by operators of visually accessible portions of designated systems during normal op erating conditions or test mode.

4. Detailed leakage inspection and measurement defined for designated systems during initial test program and thereafter.

5. An aggressive preventive maintenance program with high priority assigned to leakage-related wo rk or designated systems.

6. A review cycle for leakage-related work requests to evaluate possible modifications to keep leakage as low as is reasona bly achievable.

III.D.3.3 Improved Inplant Iodine In strumentation Under Accident Conditions Position (NUREG-0737)

a. Each licensee shall provide equipmen t and associated trai ning and procedures for accurately determining th e airborne iodine concentr ation in areas within the facility where plant personnel may be present during an accident.

• This program takes exception for those systems which cannot be tested until startup due to required plant conditions. Program documenta tion will be available onsite for NRC I&E review.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 0-0 1 8 B.3-4 b. Each applicant for a fuel-loading license to be issued prior to January 1, 1981 shall provide the equipment, training, an d procedures necessa ry to accurately determine the presence of airborne radioiodine in areas within the plant where plant personnel may be pres ent during an accident.

Clarification Effective monitoring of increasing iodine levels in the buildings under a ccident conditions must include the use of portable instru ments using sample media that will collect iodine selectively over xenon (e.g., silver ziolit e) for the following reasons:

a. The physical size of the auxiliary and/or fuel handling building precludes locating stationary monitoring instrumentation at all areas where airborne iodine concentration dat a might be required.

b. Unanticipated isolated "hot spots" may occur in locations where no stationary monitoring instrumentation is located.

c. Unexpectedly high background radia tion levels near stationary monitoring instrumentation after an accident may in terfere with filter r adiation readings.

d. The time required to retrieve samples after an ac cident may result in high personnel exposures if these filters are located in high-dose-rate areas.

After January 1, 1981, each ap plicant and licensee shall have the capability to remove the sampling cartridge to a low background, low contamination area for further analysis.

Normally, counting rooms in aux iliary buildings will not have su fficiently low backgrounds for such analyses following an accident. In the low background area, the sample should first be purged of any entrapped noble gases using nitrogen gas or clean ai r free of noble gases. The licensee shall have the capability to measure accurately the iodi ne concentrations present on these samples under accident c onditions. There should be sufficient samplers to sample all vital areas.

For applicants with fuel loading dat es prior to January 1, 1981, provide by fuel loading (until January 1, 1981) the capability to accurately det ect the presence of iodi ne in the region of interest following an accident.

This can be accomplished by using a portable or cart-mounted iodine sampler with attached single-channel analyzer (SCA). The SCA window should be calibrated to the 365 KeV of Iodine-131 using the SCA. This will give an initial conservative estimate of presence of iodine and can be used to determin e if respiratory protection is required. Care must be taken to assure that the counting system is not saturated as a result of too much activity collected on the sampling cartridge.

C OLUMBIA G ENERATING S TATION Amendment 56 F INAL S AFETY A NALYSIS R EPORT December 2001 LDC N-0 0-0 1 8 B.3-5 Columbia Generating Station Position This italicized information is historical and was provided to support the application for an operating license. The FSAR contai ns descriptions for this in strumentation in the following sections:

7.5.2.2.3 , 12.3.4.2 , 12.3.4.4 , 12.5.2.1 , 12.5.3.5 , and Emergency Plan Section 8.7.5.

Columbia Generating Station is responding to this position as follows: Four fixed, one mobile continuous air monitoring system, and one movable local alarming continuous air monitor are provided for air sampling in plant areas wh ere personnel may be pr esent during accident conditions. In addition, 10 low volume air sa mpling systems will be strategically located throughout the plant in freque ntly occupied areas to con tinuously draw air samples for subsequent analysis.

Grab samples will be obtained using varying volume air samp lers that are both ac and dc powered. Movable local alarming continuous air monitors are placed at predetermined plant locations for personnel protection and to substantiate the quality of the plant breathing atmosphere.

These monitors have local readouts (charts) and radioiodine sampling capabilities.

Energy Northwest is currently using activated charcoal cartridges for radioiodine analysis and is evaluating the attributes of s ilver zeolite. On co mpletion of a satisfactory evaluation Energy Northwest will, where applicable, incorporate silv er zeolite into its air sampling program. The charcoal cartridges are used in conjunction with a Ge (Li) gamma spectroscopy system located in a low background, low contamination area such as the radiochemistry lab in the near site facility. Prior to analysis, ca rtridges are purged in a fume hoo d using plant air, instrument air, bottled air, or bottled nitrogen which is stored onsite.

Station procedures are provided for obtaining and evaluating both routine and non-routine air samples. In addition to initial training provid ed for Health Physic s/Chemistry personnel, periodic drills are conducted in a ccordance with the Emergency Plan.

This position has been accepte d in the NRC Safety Evaluati on Report, NUREG-0892, dated December 1982, Section 12.5.2.