ML18207A591

Revision OL-23 to Final Safety Analysis Report, Chapter 18, Response to NUREG-0737 Clarification of TMI Action Plan Requirements

ML18207A591
Person / Time
Site:	Callaway
Issue date:	06/19/2018
From:	Ameren Missouri, Union Electric Co
To:	Office of Nuclear Reactor Regulation
Shared Package
ML18207A460	List: ML18207A548 ML18207A549 ML18207A550 ML18207A551 ML18207A555 ML18207A557 ML18207A558 ML18207A559 ML18207A560 ML18207A561 ML18207A562 ML18207A563 ML18207A565 ML18207A566 ML18207A568 ML18207A570 ML18207A571 ML18207A572 ML18207A573 ML18207A580 ML18207A581 ML18207A582 ML18207A583 ML18207A584 ML18207A586 ML18207A587 ML18207A588 ML18207A589 ML18207A590 ML18207A591 ML18207A592 ML18208A153 ML18208A154 ML18208A155 ML18208A161 ML18208A162 ML18208A163 ML18208A164 ML18208A165 ML18208A166 ML18208A167 ML18208A168 ML18208A169 ML18208A170 ML18208A171 ML18208A172 ML18208A173 ML18208A175 ULNRC-06442, Revision 14 to Technical Specification Bases, Table of Contents
References
ULNRC-06442
Download: ML18207A591 (157)

Text

CALLAWAY - SP18.0-iTABLE OF CONTENTSCHAPTER 18.0RESPONSE TO NUREG-0737CLARIFICATION OF TMI AC TION PLAN REQUIREMENTS Section Page18.1OPERATIONAL SAFETY...

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..........................18.1-118.1.1Shift Technical Advisor (I.A.1.1)............

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.....................18.1-118.1.2Shift Manager Administrative Duties (I.A.1.2).........

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...................18.1-418.1.3Shift Manning (I.A.1.3).............

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.....................18.1-618.1.4Immediate Upgrading of Reactor Operator and Senior ReactorOperator Training and Qualifications (I.A.2.1)...........

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.................18.1-818.1.5Administration of Training Programs (I.A.2.3).............

...........................18.1-1018.1.6Revise Scope and Criteria for Licensing Examinations(I.A.3.1).............

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...................18.1-1118.1.7Evaluation of Organization and Management Improvements ofNear-Term Operating License Applicants (I.B.1.2).........

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........................18.1-1218.1.8Guidance for the Eval uation and Development of ProceduresforTransients and Accidents (I.C.1)......

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......................18.1-1518.1.9Shift Relief and Tu rnover Procedures (I.C.2)..............

...........................18.1-1918.1.10Shift manager's Responsibilities (I.C.3)...........

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......................18.1-2118.1.11Control Room Access (I.C.4).................

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...................18.1-2118.1.12Procedures for Feedback of Operating Experience toPlant Staff (I.C.5).................

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...................18.1-2218.1.13Verify Correct Perform ance of Operating Activities(I.C.6)................

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...................18.1-2418.1.14NSSS Vendor Review of Procedures (I.C.7)..............

...........................18.1-26 CALLAWAY - SPTABLE OF CONTENTS (Continued)

Section Page18.0-ii18.1.15Pilot Monitoring of Selected Emergency Procedures for Near-term Operating License Applicants (I.C.8)...............

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......................18.1-2618.1.16Control Room Design Review (I.D.1)...............

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......................18.1-2718.1.17Plant Safety Parameter Display System (I.D.2)..........

...........................18.1-2918.1.18Special Low Power Testin g and Training (I.G.1)................

...................18.1-3118.2SITINGANDDESIGN...............

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.....................18.2-118.2.1Post-Accident Reactor Cool ant System Venting (II.B.1)..........................18.2-118.2.2DesignReviewofthePlantShielding(II.B.2).

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..........................18.2-518.2.3Postaccident Sampling System (II.B.3)....

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.................18.2-1718.2.4Training for Mitigating Core Damage (II.B.4)...

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......................18.2-2118.2.5Performance Testing of the Pressurizer Power-Operated ReliefValve(II.D.1).

18.2-2318.2.6Direct Indication of Reli ef and Safety Valve Position(II.D.3)...............

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...................18.2-2618.2.7AuxiliaryFeedwater Syst em Reliability Evaluation(II.E.1.1)............

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...................18.2-2718.2.8Auxiliary Feedwater Initiation and Indication (II.E.1.2)...

........................18.2-2918.2.9Emergency Power Supply for Pressurizer Heaters(II.E.3.1)............

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...................18.2-3218.2.10Dedicated Hydrogen Penetrations (II.E.4.1)......

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...................18.2-3518.2.11Containment Isolation D ependability (II.E.4.2)

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......................18.2-3618.2.12Accident Monitoring Instrumentation (II.F.1)....

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......................18.2-4018.2.13Instrumentation for Detect ion of Inadequate Core Cooling(II.F.2)...............

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...................18.2-58 CALLAWAY - SPTABLE OF CONTENTS (Continued)

Section Page 18.0-iii18.2.14Emergency Power for Pressurizer Equipment (II.G.1)...

........................18.2-7418.2.15Requests by NRC Inspec tion and Enforcement Bulletins(II.K.1)...............

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...................18.2-7618.2.16Orders on Facilities with Babcock & Wilcox Nucl ear Steam Supplier Systems (II.K.2)...............

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...................18.2-7718.2.17Recommendations from the Bulletins and Orders Task Force(II.K.3)..18.2-7918.2.18References............

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...................18.2-9318.3EMERGENCYPREPARATIONSANDRADIATIONPROTECTION............18.3-118.3.1UpgradeEmergencyPreparedness(III.A.1.1)........

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...................18.3-118.3.2UpgradeEmergencySupportFacilities(III.A.1.2)...........

........................18.3-118.3.3Improving Licensee Emergency Preparedness - Long Term(III.A.2)......18.3-918.3.4Integrity of Systems Outs ide of Containment (III.D.1.1)........................18.3-1118.3.5Improved Inplant Iodine Instrument ation Under Accident Conditions....18.3-1418.3.6Control Room Habitability (III.D.3.4)....................

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...................18.3-15 CALLAWAY - SP18.0-ivRev. OL-1412/04LIST OF TABLES NumberTitle18.2-2Essential/Nonessentia l Containment Penetrations18.2-3Details for the Thermocoup le/Core Cooling Monitor System CALLAWAY - SP18.0-vRev. OL-1412/04LIST OF FIGURES NumberTitle18.2-1Reactor Head Vent System 18.2-2Post-Accident Radiat ion Zones Elevation 1974'18.2-3Post-Accident Radiat ion Zones Elevation 1988'18.2-4Post-Accident Radiat ion Zones Elevation 2000'18.2-5Post-Accident Radiat ion Zones Elevation 2026'18.2-6Post-Accident Radiati on Zones Elevation 2047'-6"18.2-7Post-Accident Radiation Zones Control Building and Communications Corridor Elevations 1974' and 1984'18.2-8Post-Accident Radiation Zones Control and Di esel Generator Buildings and Communications Corr idor Elevations 2000' and 2016'18.2-9Post-Accident Radiation Zones Control and Di esel Generator Buildings and Communications Co rridor Elevations 2032' and 2047'-6"18.2-10Normalized Dose Rate De cay Curves for Airborne Source (SourceA)18.2-11Normalized Dose Rate Decay Curves for Sump Source (SourceC) with 1Percent Cs and 50Percent Cs18.2-12Functional Diagram (React or Core Subc ooling Monitor)18.2-13Reactor Vessel Level Instrumentation System18.2-14PORV Opening Ba nd - Turbine Trip with Condenser Unavailable18.2-15Nuclear Sampling System CALLAWAY - SP18.0-1Rev. OL-13 5/03CHAPTER18.018.0RESPONSETONUREG-0737,"CLARIFICATIONOF TMI ACTION PLAN REQUIREMENTS" The following discussion of t he Union Electric response to NUREG-0737 is subdivided into three Sections: 18.1 , Operational Safety; 18.2 , Siting and Design; and 18.3 , Emergency Preparations and Radiation Protection. The subsections presenting the NRC guidance are ve rbatim quotes from NRC documents.

CALLAWAY - SP18.1-1Rev. OL-21 5/1518.1OPERATIONAL SAFETY18.1.1SHIFT TECHNICA L ADVISOR (I.A.1.1)18.1.1.1NRC Guidance Per NUREG-0737 Position Each licensee shall provide an on-shift technical advisor to the Shift Manager. The shift technical advisor (STA) may se rve more than one unit at a mult iunit site if qualified to perform the advisor function for the various units.The STA shall have a bachelor's degree or equi valent in a scientific or engineering discipline and have received specific training in the response and analysis of the plant for transients and accidents. The STA shall also receive training in plant design and layout, including the capabilities of instrumentation and contro ls in the control room. The licensee shall assign normal duties to the STAs that pertain to the engineering aspects of ensuring safe operations of the plant, includ ing the review and eval uations of operating experience.Clarification The staff letter of October 30, 1979 from H. R. Denton to All Operating Nuclear Power Plants clarified the short-term STA requirements. The letter indicated that the STAs must have completed all training by January 1, 1981. This paper confirms these requirements and requests additi onal information.The need for the STA position ma y be eliminated when the qualifications of the shift managers and senior operators have been upgraded and the man-mach ine interface in the control room has been acceptably upgraded. However, until those long-term improvements are attained, the need for an STA pr ogram will continue. The staff has not yet established the detailed elements of t he academic and training requirements of the ST A beyond the guidance given in it s October 30, 1979 letter. Nor has the staff made a decision on the level of upgr ading required for li censed operating personnel and the m an-machine interface in the control room that would be acceptable for eliminating the need of an STA. Until these requirements for eliminating the STA position have been established, the staff continues to require that, in addition to the staffing requirements specified in its July 31, 1980 letter (as revised by item I.A.1.3 of this report), an STA be available fo r duty on each operating shift when a plant is being operated in Modes 1-4 for a PW R and Modes 1-3 for a BWR. At other times, an STA is not required to be on duty.

Since the October 30 , 1979 letter was issued, several efforts have been made to establish, for the longer term , the minimum level of experi ence, education, and training CALLAWAY - SP18.1-2Rev. OL-21 5/15for STAs. The efforts include work on the revi sion to ANS-3.1, work by the Institute of Nuclear Power Operations (INPO), and internal staff efforts.

INPO recently made av ailable a document entitled "Nuclear Power Plant Shift Technical Advisor--Recommendations fo r Position Description, Qual ifications, Education, and Training." A copy of Revision 0 of this document, dated April 30, 1980, is attached as Appendix C to NUREG-0737. Sections 5 and 6 of the INPO do cument describe the education, training, and experience requirements for STAs. The NRC staff finds that the descriptions set forth in Sections 5 and 6 of Revision 0 to the IN PO document are an acceptable approach for t he selection and training of personnel to staff the STA positions. Note: This should not be interpreted to mean that this is an NRC requirement at this time. The intent is to refer to the INPO document as acceptable for interim guidance for a utility in planning its STA pr ogram over the long te rm (i.e., beyond the January 1, 1981 requirement to have STAs in place in a ccordance with the qualification requirements specified in the staff's October 30, 1979 letter).No later than January 1, 1981, all licensees of operating reactors shall provide this office with a description of their STA training program and their plans for requalification training.

This description shall indicate the level of training attained by STAs by January 1, 1981 and demonstrate conformance wi th the qualification and trai ning requirements in the October 30, 1979 letter. Applicants for operating lice nses shall prov ide the same information in this application, or amendments thereto, on a schedule consistent with the NRC licensing review schedule.No later than January 1, 1981, all licensees of operating reactors shall provide this office with a description of their long-term STA program, including qualification, selection criteria, training plans, and plans, if any, fo r the eventual phaseout of the STA program. (Note: The description shall include a comparison of the licensee/applicant program with the above-mentioned INPO document. This request solicits industry views to assist NRC in establishing long-term improvements in the STA program. Applicants for operating licenses shall provide the same information in their application, or amendments thereto, on a schedule consistent with t he NRC licensing review schedule.)18.1.1.2Union Electric ResponseGeneralThe NRC issued a Policy Statement on Engineering Expertise on Shift in October 1985. The Policy Statement permits ei ther of two options to be used to implement long term goals toward upgrading the qualif ications and training of operating staffs. These are Option 1: Combined SRO/ST A Position and Option 2: Continued use of STA Position.

Either of these opti ons may be used to meet the requirements of NUREG-0737, Item I.A.1.1. Also, either Op tion 1 or 2 may be used on each shift. The complete requirements for the op tions are as follows:

Option 1: Combined SRO/STA Position CALLAWAY - SP18.1-3Rev. OL-21 5/15 This option is satisfied by assigning an individual with the following qualifications to each operating shift crew as one of the SROs (preferably the Shift Manager) required by 10 CFR 50.54 (m)(2)(i):1.Licensed as a senior operator on t he nuclear power uni t(s) to which assigned and;2.Meets the STA training criteria of NUREG-0737, Item I.A.1.1, and one of the following educat ional alternatives:a.Bachelor's degree in engineeri ng from an accredited institution;b.Professional Engineer's license obtaine d by the successful completion of the PE examination;c.Bachelor's degree in enginee ring technology from an accredited institution, including c ourse work in the phys ical, mathematical, or engineering sciences; or d.Bachelor's degree in a physi cal science from an accredited institution, including c ourse work in the phys ical, mathematical, or engineering sciences.

Option 2: Continued Use of STA PositionThis option is satisfied by placing on each shift a dedicated Shift Technical Advisor (STA) who meets the STA criteria of NUREG-0737, Item I.A.1.1. The STA should assume an active role in shift activities. For example, the STA should review plant logs, participate in shift turnover activities, and maintain an awareness of plant configuration and status.As stated in NUREG-0737 and the background to the NRC Policy Statement (discussed below), the requirement for an STA qualified person in the power plant in addition to an SRO licensed Shift Manager wa s intended to be a temporar y requirement until the qualifications of the Shift Manager and senior operators ar e upgraded and control boards are reviewed and modified to make information and contro ls more useful to the operators. This is consistent with the industry consensus established by INPO standard GPG-01, "Nuclear Power Plant Shift Te chnical Advisor Po sition Description Qualifications, Education and Training" which refers to the fact of this position being "eliminated" when certai n additional actions are completed. The December 17, 1983 approved copy of ANSI/ANS 3.

1 which also referred to th is position as "interim".The NRC staff has completed the review of the Union Electric qualification program developed to address NUREG-0737, Item I.A.1.1. The program and NRC staff review results are discussed below.

CALLAWAY - SP18.1-4Rev. OL-21 5/15 Man-Machine Interface Upgrade The man-machine interface in the contro l room has been upgraded by means of an extensive control room design review which included human factors input. For a detailed description of this effort refer to Section 18.1.16 and 18.1.17.Operator qualification upgr ading in accordance with NUREG

-0737, Item I.A.1.1 is discussed in Section 13.2

.Union Electric has either a se nior operator or an engineer, who meets the STA training criteria of NUREG-0737, for each operating shift to report to the control room when the reactor is in Modes1-4.

The individuals fulfilling the STA requirement shall have a bachelor's degree in engineering or related science wh ich includes or is supplem ented to include sixty (60) semester hours of co llege level education in mathematics, reactor physics, chemistry, materials, reactor thermodynami cs, fluid mechanics, heat transfer, electrical and reactor control theory.

The individuals fulfilling the STA requirement shall also have one year of experience at a nuclear power plant including six months onsit e at the time the i ndividual is required on shift. Nuclear power plant experience is time associated with: preoperational and startup testing activities; military, non-stationary, propulsion or production nuclear plants; reactor simulator training; or on-the-job training.The STA qualification program includes: training in plant systems; a course in mitigating core damage; and specif ic training in the response and analysis of the plant for transients and accidents utiliz ing the Callaway Plant simulator.

A retraining and requalification progra m has been developed.The Director, Nuclear Operations is res ponsible for the qualification of the STAs.

The senior operators report to the Manager , Nuclear Operations. The description and functions of the senior operators are further detailed in Sections 13.1.2.2 and 13.1.3.1.18.1.1.3Conclusion Union Electric's actions to upgrade qualification of operating staf f and the man-machine interface for control room pe rsonnel are consistent with the intent and specifics of the long-term resolution of NU REG-0737, Item I.A.1.1.18.1.2SHIFT MANAGER ADMINISTRATIVE DUTIES (I.A.1.2)18.1.2.1NRC Guidance per NUREG-0578 Position CALLAWAY - SP18.1-5Rev. OL-21 5/15A.The highest level of corporate management of each licensee shall issue and periodically reissue a management directive that emphasizes the primary management responsibility of the Shift Manager for safe operation of the pl ant under all conditions on his shift and that clearly est ablishes his co mmand duties.B.Plant procedures sha ll be reviewed to ensur e that the duties, responsibilities, and authority of the Shift Manager and control room operators are properly defined to effect the establishment of a definite line of command and clea r delineation of the command decision authority of the shift manager in the c ontrol room, relative to other plant management personnel. Particular emphasis shall be placed on the following:1.The responsibility and authority of the Shift Manage r shall be to maintain the broadest perspective of operational conditions affecting the safety of the plant as a matter of highest priority at all times when on duty in the cont rol room. The princi ple shall be reinforced that the Shift Manager should not become totally involved in any single operation in times of emergency when multiple operations are required in the control room.2.The Shift Manager, until properly relieved, shall remain in the control room at all times during accident situations to direct the activities of control room operators. Person s authorized to relieve the Shift Manager shall be specified.3.If the Shift Manager is temporar ily absent from t he control room during routine operations , a lead control ro om operator shall be designated to assume the contro l room command function. These temporary duties, resp onsibilities, and authori ty shall be clearly specified.C.Training programs for Shift Manager shall emphasize and reinforce the responsibility for safe operat ion and the manage ment function the Shift Manager is to provide for ensuring safety.D.The administrative duties of the Shift Manager shal l be reviewed by the senior officer of each utility responsible for plant operations.

Administrative functions that detract from or are s ubordinate to the management responsibility for ensuring the sa fe operation of the plant shall be delegated to other operations personnel not on duty in the control room.

CALLAWAY - SP18.1-6Rev. OL-21 5/1518.1.2.2Union Electric ResponseThe Senior Vice President and Chief Nuclear Officer, issues and reviews on an annual basis a management directive which emphasizes the responsibilities on the Shift Manager and clearly establ ishes his command duties dur ing all operating conditions.

Plant administrative procedures define the duties, responsibilities and authority of Shift Manager, Operating Supervisors and Unit Re actors Operators. Administrative procedures further define the line of command for the Shift Manager. The Shift Manager reports to the Director, Nucl ear Operations or the Manager, Nuclear Operations during normal operations and to the Emergency Duty Officer during an emergency. The Shift Manager is the senior licensed management representative on site during weekends and backshifts. The Shift Manager is responsible to direct operati on of the unit. This allows the Shift Manager to direct hi s attention to overall plan t operations for which he is responsible. The Director, Nuclear Operations, or the Manager, Nuclear Operations, shall designate senior reactor operat ors who may relieve the Shift Manager.

In conjunction with the annual review of the management directive defining the Shift Manager's authorities and responsibilities, the Senior Vice President and Chief Nuclear Officer shall assess the administrative duties undertaken by the Shift Manager. If these duties are found to detract from the Shift Manager's responsibility for safe operation of the plant, they shall be delegated to other appropriate members of the plant staff.

A licensed Operating Supervisor is present on the plant site at all times when reactor fuel is on site.18.1.2.3Conclusion Union Electric's commitment to the establishment and annual review of management directives defining the responsibilities and authority of the Shif t Manager and to the implementation of the tr aining programs in accordance with 10 CFR 55 meets the intent of NUREG-0737, Item I.A.1.2.18.1.3SHIFT MANNING (I.A.1.3)18.1.3.1NRC Guidance Per NUREG-0737 PositionThis position defines shift manning requirements for normal operation. The letter of July 31, 1980 from D. G.

Eisenhut to All Power Reactor Licensees and Applicants sets forth the interim criteria for shift staffing (to be effective pending general criteria that will be the subject of future rulemaking).

Overtime restrictions were also included in the July 31, 1980 letter.Clarification CALLAWAY - SP18.1-7Rev. OL-21 5/15 Page 3 of the July 31, 1980 letter is superseded in its entiret y by the following:Licensees of operating plants and applicants for operating licenses shall include in their administrative procedures (required by license conditions) provisions governing required shift staffing and movement of key individual s about the plant. These provisions are required to ensure that qualified plant personnel to man the operational shifts are readily available in the event of an abnormal or emergency situation.

These administrative procedures shall also set forth a policy, the objective of which is to prevent situations where fa tigue could reduce the ability of operating personnel to keep the reactor in a safe condition. The controls established should assure that, to the extent practicable, personnel are not assigned to shif t duties while in a fatigued condition that could significantly reduce their mental aler tness or their decision making ability. The controls shall apply to the plant staff who perform safety-related functions (e.g., senior reactor operators, reactor operators, auxiliary operators, health physicists, and key maintenance personnel).

IE Circular No. 80-02, "Nuclear Power Plant Staff Work Hours", dated F ebruary 1, 1980 discusses the concern of overtime work fo r members of the plant staff who perform safety-related functions. The guidance contained in IE Circular No. 80-02 was amended by the July 31, 1980 letter. In turn, the overtime guidance of the July 31, 1980 letter was revised in Section I.A.1.3 of NUREG-0737. The NRC has issued a policy statement which further revises the overtime guidance as stated in NUREG-0737. This guidance is as follows:

Enough plant operating pers onnel should be employed to maintain adequate shift coverage without routine heavy us e of overtime. The objec tive is to have operating personnel work a normal 8-hour day, 40-hour week while t he plant is operating. However, in the event that unforeseen problems require substantial amounts of overtime to be used, or during extended periods of shutdown for re fueling, major maintenance or major plant modifications, on a temporary basis, the fo llowing guidelines shall be followed:a.An individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> straight (excluding shift turnover time).b.An individual should not be permitte d to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24-hour period, nor more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48-hour period, nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any sev en day period (all excluding shift turnover time).c.A break of at least eight hours s hould be allowed betw een work periods (including shift turnover time).d.Except during extended shutdown peri ods, the use of overtime should be considered on an individual basis and not for the entire staff on shift.

CALLAWAY - SP18.1-8Rev. OL-21 5/15However, recognizing that circumstances may arise requiring devi ation from the above restrictions, such deviation shall be authorized by the pl ant manager or his deputy or higher levels of management in acco rdance with published pr ocedures and with appropriate documentation of the cause.

NRC encourages the development of a staffing policy t hat would permit the licensed reactor operators and senior reactor operators to be periodically assigned to other duties away from the control board during their normal tours of duty.Operating license applicants shall complete t hese administrative proc edures before fuel loading. Development and implementation of the administrative procedures at operating plants will be reviewed by the Office of Inspection and Enforcement beginning 90 days after July 31, 1980.

See section III.A.1.2 (OF NUREG-0737) for minimum staffing and augment capabilities for emergencies."18.1.3.2UE ResponseShift staffing is discussed in Section 13.1 of the FSAR. Uni on Electric has an administrative procedure governing shift manning and movem ent of key individuals. Unexpected absences are also addressed in plant procedures. Additional information on staffing requirements is contained in Technical Specifications, Table 16.12-1 and the RERP.18.1.3.3Conclusion In 2009, new regulation 10 CFR 26, Subpart I, became effective. This regulation addresses worker fatigue and specifies limits and contro ls on working hours. The requirements of 10 CFR 26, Subpart I, supersede prio r worker fatique guidance. It distinguishes between work hour controls and fatigue m anagement and stre ngthens the requirements for both. Union Electric (dba AmerenUE) observ es the work hour restrictions required by 10 CFR Part 26, Subpart I. In addi tion, Union Electric continues to meet the intent of NRC's guidance for minimum shift complement.18.1.4IMMEDIATE UPGRADING OF REACTOR OPERATOR AND SENIOR REACTOROPERATOR TRAINING AND QUALIFICATIONS (I.A.2.1)18.1.4.1NRC Guidance Per NUREG-0737 Position Effective December 1, 1980, an applicant for a senior reactor operator (SRO) license will be required to have been a licensed operator for 1 year.Clarification CALLAWAY - SP18.1-9Rev. OL-21 5/15Applicants for SRO either co me through the operations chai n (C operator to B operator to A operator, etc.) or are degree-holding staff engineers who obtain licenses for backup purposes.In the past, many individ uals who came through the operat or ranks were administered SRO examinations without first being an operator. This was cl early a poor practice and the letter of March 28, 1980 requires reactor operator experience for SRO applicants.However, NRC does not wish to discourage staff enginee rs from becoming licensed SROs. This effort is encouraged because it forces engineers to broaden their knowledge about the plant and its operation.

In addition, in order to attract degree-holding engineers to consider the shift manager's job as part of their career development, NRC should provide an alternate path to holding an operator's license for 1 year.

The track followed by a high-school gr aduate (a nondegreed indi vidual) to become an SRO would be 4 years as a control room operator, at least one of which would be as a licensed operator, and particip ation in an SRO training prog ram that includes 3 months on shift as an extra person.

The track followed by a degr ee-holding engineer would be, at a minimum, 2 years of responsible nuclear power plant experience as a staff engineer, participation in an SRO training program equivalent to a cold applicant training program, and 3 months on shift as an extra person in tr aining for an SRO position.

Holding these positions ensures that individuals who will direct the li censed activities of licensed operators have had t he necessary combination of education, training, and actual operating experience pr ior to assuming a supervisory role at that facility.The staff realizes that the necessary knowledge and experience can be gained in a variety of ways. Consequently, credit for equivalent experience should be given to applicants for SRO licenses.Applicants for SRO licenses at a facility may obtain their 1-year operating experience in a licensed capacity (operator or senior operator) at another nuclear power plant. In addition, actual operating exper ience in a position that is equivalent to a licensed operator or senior operator at military propulsion reactors will be acceptable on a one-for-one basis. Individual applicants must document this experience in their individual applications in sufficient detail so that the staff can make a finding regarding equivalencyApplicants for SRO licenses who possess a degree in engineering or applicable sciences are deemed to meet t he above requirement, provided t hey meet the requirements set forth in sections A.1.a and A.2 in enclosure 1 in the letter from H. R. Denton to all power CALLAWAY - SP18.1-10Rev. OL-21 5/15reactor applicants and licensees, dated Marc h 28, 1980, and have participated in a training program equivalent to that of a cold senior operator applicant.NRC has not imposed on the 1-year experience requirement on cold applicants for SRO licenses. Cold applicants are to work on a facility not ye t in operation; their training programs are designed to supply t he equivalent of the experien ce not available to them.18.1.4.2UE Response UE has committed to conduct its licensed operator training and requalification programs in accordance with the requirements of 10 CFR Part 55 and INPO accredited programs as referenced in Section 13.2. In addition, UE complies with the training and qualification recommendations deli neated in INPO guidelines for the training of licensed personnel. The Callaway Plant Training Procedures provide detailed outli nes of curricula for such training sequences.

Additional discussion of UE commitments relative to training and requalification programs is presented in Section 18.1.6

.18.1.4.3Conclusion Union Electric has committed to comply with 10 CFR 55 requirements for operator licensing and requalification progra ms and INPO accredited programs.18.1.5ADMINISTRATION OF TRAINING PROGRAMS (I.A.2.3)18.1.5.1NRC Guidance Per NUREG-0737 PositionPending accreditation of trai ning institutions, licensees and applicants for operating licenses will ensure that tr aining center and facility instructors who teach systems, integrated responses, transient, and simu lator courses demonstr ate senior reactor operator (SRO) qualifications and be enrolled in appropriate requal ification programs.Clarification

The above position is a short-te rm position.

In the future, accreditation of training institutions will include review of the procedure fo r certification of instructors. The certification of instructors may, or may not, include successful completion of an SRO examination.The purpose of the examination is to provide the NRC with reason able assurance during the interim period that instruct ors are technica lly competent.

CALLAWAY - SP18.1-11Rev. OL-21 5/15 The requirement is directed to permanent members of training staff who teach the subjects listed above, including members of other organizations who routinely conduct training at the facility.

There is no intention to require guest lecturers who are experts in particular subjects (reactor theory, instrumentation, thermodynam ics, health physics, chemistry, etc.) to successfully complete an SRO examination. No r is it intended to require a system expert, such as the instrument and cont rol supervisor teaching the control rod drive system, to co mplete an SRO examination."18.1.5.2Union Electric Response All operator license program instructors are required to participate in requalification programs, which include simulato r training, for licensed operators. In addition, licensed training instructors engaged in operator training participat e in the following activities:a.periodic onshift assignmentsb.review of facility ope rating and emergency operat ing procedures as they are developedc.participation in instructor certification programs, such as those proposed by INPO This material is discussed further in Section 13.2.2.18.1.5.3Conclusion Union Electric has committed to comply wit h NRC guidance relative to the training and qualification of nuclear training staff, and meets the legal requirements of 10 CFR 55 where SRO licenses are required.18.1.6REVISE SCOPE AND CRITERIA FOR LICENSING EXAMINATIONS(I.A.3.1)18.1.6.1NRC Guidance Per NUREG-0737 Position Simulator examinations will be included as a part of the lic ensing examinations.Clarification The clarification does not alter the staff's position regard ing simulator examinations.

The clarification does provide additional preparation time for utility companies and NRC to meet the examination requirements as stated. A stud y is under way to consider how CALLAWAY - SP18.1-12Rev. OL-21 5/15 similar a noniden tical simulator should be for a valid examination.

In addition, present simulators are fully booked months in advance.Application of this requirement was stat ed on June 1, 1980 to applicants where a simulator is located at the facility. Starting October 1, 1981 , simulator exam inations will be conducted for applicants of facilities th at do not have simula tors at the site.NRC simulator examinations normally require 2 to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Normally, two applicants are examined during this time period by two examiners. Utility companies should make the necessary arrangements with an appropriate simulator training center to provide time for these examinations. Preferably, these examinations should be schedul ed consecutively with the balan ce of the examination. However, they may be schedul ed no sooner than 2 weeks prio r to and no later than 2 weeks after the balance of the examination.18.1.6.2Union Electric Response Utilization of the Callaway simu lator is incorporated into t he requalification programs for operators as discussed in Section 13.2. The Callaway Plant Tr aining procedures also address in detail, the curricula for licen sed personnel training and requalification.18.1.6.3Conclusion Union Electric has committ ed to NUREG-0737 guidance with regard to the NRC's revised scope and criteria for license examinations. In addition, UE ha s incorporated simulator examinations into it's training program. These commitments comply fully with NRC guidance as stated in NUREG-0737 relative to licensing examinations.18.1.7EVALUATION OF ORGANIZATION AND MANAGEMENT IMPROVEMENTS OFNEAR-TERM OPERATING LICENSE APPLICANTS (I.B.1.2)18.1.7.1NRC Guidance Per NU REG-0694 and NUREG-0737 Position The licensee organization shal l comply with t he findings and requirements generated in an interoffice NRC review of licensee organization and management. The review will be based, in part, on an NRC document entitled "Draft Criteria for Utility Management and Technical Competence." The first draft of this document was dated Februar y 25, 1980. The current draft was issued for interim use and public comment in September, 1980 as NUREG-0731, "Guidelines for Utility Management Structure and Technical Resources." These draft guidelines address the organization, resources, training, and qualifications of plant staff and management (both onsite and of fsite) for routine operations and the resources and activities (both onsite and offsite) for accident conditions.

CALLAWAY - SP18.1-13Rev. OL-21 5/15The licensee shall establish a group that is independent of the plant staff but is assigned onsite to perform independ ent reviews of plant operational activities and a capability for evaluation of operating experiences and nuclear power plants.

Organizational changes are to be implemented on a schedule to be det ermined prior to fuel loading.

Corporate management of t he utility-owner of a nuclear power plant shall be sufficiently involved in the operational phase activities, including plant modifica tions, to ensure a continual understanding of plant conditions and safety considerations. Corporate management shall establish safety standards for the operation and maintenance of the nuclear power plant. To t hese ends, each utility-owner shall establish an organization, parts of which shall be locat ed onsite, to: perform independent reviews and audits of plant activities; provide te chnical support to the plant staff for maintenance, modifications, operational problems, and operational analysi s; and aid in the establishment of programmatic requirements for plant activities.The licensee shall establish an integrated organizati onal arrangement to provide for the overall management of nuc lear power plant operations. This organi zation shall provide for clear management control and effective lines of au thority and communication between the organizational units involved in the management, te chnical support, and operation of the nuclear unit.

The key characteristics of a typi cal organization arrangement are:a.Integration of all nec essary functional respons ibilities under a single responsible head.b.The assignment of resp onsibility for the safe op eration of the nuclear power plant(s) to an upper level executive position.

Each applicant for an operating license shall establish an onsite independent safety engineering group (ISEG) to perform independent review s of plant operations.The principal function of the ISEG is to examine plant oper ating characteristics, NRC issuances, Licensing Informat ion Service advisories, and ot her appropriate sources of plant design and operating experience information that may indicate areas for improving plant safety. The I SEG is to perform independent review and audits of plant activities, including maintenance, modifi cations, operational proble ms, and operational analysis, and aid in the establishment of programmatic requirements for plant activities. Where useful improvements can be achieved, it is expected that th is group will develop and present detailed recommendations to corporate management for such things as revised procedures or equipm ent modifications.

Another function of the ISEG is to maintain survei llance of plant operations and maintenance activities to pr ovide independent verification th at these activities are CALLAWAY - SP18.1-14Rev. OL-21 5/15 performed correctly and that hum an errors are reduced as far as practicable. ISEG will then be in a position to adv ise utility management on the overall qual ity and safety of operations. ISEG need not perform detailed audits of plant operati ons and shall not be responsible for sign-off func tions such that it becomes involved in the operating organization.Clarification

The new ISEG shall not replace the plant oper ations review commit tee (PORC) and the utility's independent review and audit group as specified by current staff guidelines (Standard Review Plan, Regulatory 1.33, Standard Technical Spec ifications). Rather, it is an additional independent group of a minimum of five dedi cated, full-time engineers, located onsite, but reporting offsite to a corporate offici al who holds a high-level, technically oriented position that is not in the managemen t chain for power production.

The ISEG will increas e the available technical expert ise located onsite and will provide continuing, systematic, and i ndependent assessment of plant ac tivities. Integrating the shift technical advisors (STAs) into the ISEG in some way would be desirable in that it could enhance the group's contact with and know ledge of day-to-day plant operations and provide additional expertise. However, the STA on shift is necessarily a member of the operating staff and c annot be independent of it.

It is expected that the ISEG may interface with the qualit y assurance (QA) organization, but preferably should not be an integral part of the QA organization.

The functions of the ISEG require daily contact with the operating personnel and continued access to plant fac ilities and records. The IS EG review functions can, therefore, best be carr ied out by a group physi cally located onsite. However, for utilities with multiple sites, it may be possible to perform portions of the independent safety assessment function in a centralized location for all the utilities' plants. In such cases, an onsite group still is r equired, but it may be sl ightly smaller than woul d be the case if it were performing the entire independent safety assessment function. Such cases will be reviewed on a case-by-case basis.At this time, the requirement for establishi ng an ISEG is being applied only to applicants for operating licenses in accordance with Action Plan Item I.B.1.2. The staff intends to review this activity in about a year to determine its effectiveness and to ascertain whether changes are required. Applicability to operating plants wil l be considered in implementing long-term improvements in or ganization and managem ent for operating plants (Action Plan Item I.B.1.1)."18.1.7.2Union Electric ResponseThe Director, Nuclear Oversight is responsible for independent reviews of Callaway Plant operational activities. The Performance Improvement Departm ent is responsible for the Callaway Plant Operat ing Experience Program.

CALLAWAY - SP18.1-15Rev. OL-21 5/1518.1.7.3ConclusionsUnion Electric has establis hed an organization whose authorities and responsibilities are consistent with the guidanc e in NUREG-0731.

The UE organizati on provides for integration of all functi onal responsibilities under a single responsible head and the responsibility for safe operation of the nuclear plant is assigned to an upper level executive position. The sepa ration of key organizations such as Nuclear Oversight and Radiation Protection from operating pressures is provided. Members of the organization exceed the minimum educational requirements set forth in NUREG 0731 and referenced in Regulatory Guide 1.8 an d ANS 3.1. Minimum requirements of nuclear power experience are also satisfied through va rious training programs and on-the-job experience.18.1.8GUIDANCE FOR THE EVALUATION AND DEVELOPMENT OF PROCEDURESFORTRANSIENTS AND ACCIDENTS (I.C.1)18.1.8.1NRC Guidance Per NUREG-0737 Position In letter of Sept ember 13 and 27, October 10 and 30, and November 9, 1979, the Office of Nuclear Reacto r Regulation required lic ensees of operating plants, applicants for operating licenses, and licensees of plants under construction to perform analyses of transients and accidents, prepare em ergency procedures gui delines, upgrade emergency procedures, includi ng procedures for operating with natural circulation conditions, and to c onduct operator retraining (also refe r to Item I.A.2.

1). Emergency procedures are required to be c onsistent with the actions necessary to cope with the transients and accidents 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 em ergency procedure guidelines were established, however, some difficulty in completing these requirements has been experienced. Clarification of the scope of the task and appropriate schedul e revisions are being developed. In the course of the review of these matters on Babcock and Wilcox (B&W)-designed plants, the staff will follow up on the bulletin and orders matters relating to analysis methods and results, as listed in NUREG-0660, Appendix C (refer to 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, items 6, 35, 37, 38, 41, 47, 55, 57).Clarification

The letters of September 13, 27, Octobe r 10 and 30, and November 8, 1979 required that procedures and op erator training be developed for transients and accidents. The initiating events to be considered should include the events presented in the Final Safety Analysis Report (FSAR): loss of instrumentation buses and natural phenomena such as earthquakes, floods, and tor nadoes. The purpose of this paper is to clarify the CALLAWAY - SP18.1-16Rev. OL-21 5/15requirements and add additional requirements for the reanalysis of transients and accidents and inadequate core cooling.Based on staff reviews to da te, there appear to be some re curring deficiencies in the guidelines being developed. Specifically, the staff has found a lack of justification for the approach used (i.e., symptom-event, or fu nction-oriented) in developing diagnostic guidance for the operator and in procedural development. It has also been found that although the guidelines take implicit credit for the oper ation of many systems or components, they do not addre ss the availability of thes e systems under expected plant conditions nor do they address corrective or alternative actions that should be performed to mitigate the event should these systems or components fail.

The analyses conducted to date for guide line and procedure development contain insufficient information to a ssess the extent to wh ich multiple failures are considered.

NUREG-0578 concluded that the single-failure criterion was not considered appropriate for guideline de velopment and call ed for the consideration of multiple failures and operator errors. Theref ore, the analyses that s upport guideline and procedure development should consider the occurrences of multiple and consequent ial failures. In general, the sequence of events for the transients and accidents and inadequate core cooling analyzed should postulate multiple failures such that, if the failures were unmitigated, conditions of inadequate core cooling would result.

Examples of multiple failure events include:a.Multiple tube ruptures in a single steam generator and tube rupture in more than one steam generator.b.Failure of main and auxiliary feedwater.c.Failure of high-pressure reactor coolan t makeup system.d.An anticipated transient without scram (ATWS) event following a loss of offsite power, stuck-open relief valve or safety/relief valve, or main feedwater.e.Operator errors of om ission or commission.

The analyses should be ca rried out far enough into the event to ensure that all relevant thermal/hydraulic/neutronic phen omena are identified (e.g., upper head voiding due to rapid cooldown, steam gen erator stratification).

Failures and operat or errors during the long-term cooldown period should also be addressed.

The analyses should support devel opment of guidelines that define a logica l transition from the emergency proc edures into the inade quate core cooling procedure, including the use of instrumentation to identify inadequate core cool ing conditions. Rationale for CALLAWAY - SP18.1-17Rev. OL-21 5/15 this transition should be discu ssed. Additional in formation that should be submitted includes:a.A detailed description of the methodology used to develop the guidelines.b.Associated control func tion diagrams, sequence-of-event diagrams, or others, if used.c.The bases for multiple and consequential failure considerations.

d.Supporting analysis, in cluding a description of any computer codes used.e.A description of the applicability of any generic results to plant specific applications.Owners' Group or vendor submittals may be referenced as appropriate to support this reanalysis. If Owners' Group or vendor submittals have already been forwarded to the staff for review, a brief description of the submittals and just ification of their adequacy to support guideline development is all that is required.Pending staff approval of t he revised analysis and guidelines, the staff will continue the pilot monitoring of emergency procedures described in Ta sk Action Plan Item I.C.8 (NUREG-0660). For PWRs, this will involve review of the loss-of-coolant, steam-generator tube r upture, loss of main feedwater, and inadequate core cooling procedures. The adequacy of eac h PWR vendor's guidelines w ill be identif ied to each NTOL during the emergency-procedure review. Since t he analysis and guidelines submitted by the General Electric Company (GE) Owners' Group that comply with the requirements stated above have been reviewed and approved for trial implementation on six plants with applications for operating licenses pending, the interim program for BWRs will consist of trial implementation of these six plants.

Following approval of analysis and guidelines and the pilot monito ring of emergency procedures, the staff will ad vise all licensees of the adequacy of the guidelines for application to their plants. Consideration will be given to human-factors engineering and system operational characteri stics, such as informatio n transfer under stress, compatibility with operator tr aining and control-room des ign, the time required for component and system re sponse, clarity of procedural actions, and control-room personnel interactions. When this determination has been made by the staff, a long-term plan for emergency procedure review, as described in Task Action Plan Item I.C.9, will be made available. At that time, the reviews currently being conducted on NTOLs under Item I.C.8 will be discontinued, and the review required for applicants for operating licenses will be as descri bed in the long-term plan. Depending on the information submitted to support developm ent of emergency procedures for each reactor type or vendor, this transition may take place at different times. For example, if the GE guidelines are shown to be effective on the six plants chos en for pilot mo nitoring, the long-term plan for BWRs may be complete in early 1981. Operating plants and CALLAWAY - SP18.1-18Rev. OL-21 5/15applicants will then hav e the option of implementing t he long-term pl an in a manner consistent with their operati ng schedule, provided they meet the final dat e required for implementation. This may require a plant that was re viewed for an operating license under Item I.C.8 to revise its emergency procedures again prior to the final implementation date for Item I.

C.9. The extent to which the long-term program will include review and approval of plant-specific procedures for operating plants has not been established. Our objective, however, is to minimize the amount of plant-specific procedure review and approval required. The staff believ es this objective can be acceptably accomplished by concentrating the staff review and approval on generic guidelines. A key element in meeting this objective is the use of staff-approved generic guidelines and guideli ne revisions by licensees to develop procedures. For this approach to be effective, it is imperative that, once the staff has issued approval of a guideline, subsequent revisions of the guideline should not be implemented by licensees until reviewed and approved by the staff. Any changes in plant-specific procedures based on unapproved guidelines could constitute an unreviewed safety issued under 10 CFR 50.59. Deviations from this approach on a plant-specific basis would be acceptable provided the basis is submitted by the licensee for staff review and approval. In this case, deviations from generic guide lines should not be implemented until staff approval is formally received in writing. Interim implementati on of analysis and procedures for small-break loss-of-coolant accident and inadequate core cool ing should remain on the schedule contained in NUREG-0 578, Recommendation 2.1.9."The NRC issued additional requirements and guidance relative to this issue in Supplement 1 to NUREG-0737 (Generic Letter 82-33). The requirements and guidance in Supplement 1 to NU REG-0737 replaced the corresponding requirements in NUREG-0737.18.1.8.2Union Electric ResponseThrough participation in the Westinghouse Ow ners' Group (WOG), t he SNUPPS utilities have been involved in the development of Westinghouse guidelines for accidents that exceed existing design basis and guidelines for in adequate core cooling.

Guidelines have been submitted to the NRC for review and have been approved. These guidelines have been used for the preparat ion of Callaway specif ic Emergency Operating Procedures and inadequate co re cooling procedures.The WOG has supported development of additional guidelines for comparison to existing guidelines for emergency operation. Events to be rec onsidered in the light of NUREG-0737 guidance (i.e., multiple failures) are:- Large LOCA- Small LOCA- Feedline break- Steamline break

- Steam generator tube rupture CALLAWAY - SP18.1-19Rev. OL-21 5/15The WOG has completed the expanded guidelines which include the bases for detailed procedures to mitigate inadequate core cooli ng. The WOG has subm itted an update of Westinghouse Topical Report WCAP-9691, which used event tree methodology to extend a review of analyzed accidents to include certain multip le failure considerations. WCAP-9691 was updated to expand the Westi nghouse Reference Operating Instruction set through considerati on of extended coverage prov ided by current Emergency Operating Instruction Guidelines. A significant number of the original WCAP-9691 event sequences were provided with additional "procedural cover age" as a result of the evaluation commissioned by t he Owners' Group. By lett er dated December 24, 1984, the NRC staff has approved the WOG guidelines (Westin ghouse Emergency Response Guidelines, Revision 1) for implementation.Union Electric has developed emergency operating procedures consistent with the WOG guidelines for the events enum erated above. UE has ev aluated each guideline and developed plant emergency operati ng procedures specifically applicable to Callaway Plant. Consistent with the requirements of Supplement 1 to NUREG-0737, UE has submitted a Procedures Generat ion Package (PGP) for NRC review. The NRC review of the PGP resulted in the submittal of additional information (ULNRC-659, 9/7/83) regarding verification and validat ion of the EOPs. Informat ion to address the process that was used to derive the instrumentation and control charac teristics was submitted to NRC via ULNRC-1242, 1/

14/86 and ULNRC-1323, 7/9/86.18.1.8.3Conclusions Union Electric's commitment to develop emergency operating procedures based on the WOG guidelines is consistent with NUREG-0737, Supplement 1 requirements. UE has tailored the Westinghouse guideli nes so that they are directly applicable to Callaway Plant. In addition, UE has provided emergency operating procedures to Westinghouse for review (See Section 18.1.14) in accordance with NUREG-0737 guidance.18.1.9SHIFT RELIEF AND T URNOVER PROCEDURES (I.C.2)18.1.9.1NRC Guidance Per NUREG-0579 Position The licensee shall review and revise, as necessary, the plant procedure for shift and relief turnover to ensure the following:1.A checklist shall be provided for the oncoming and offgoing control-room operators and the oncoming shift manager to complete and sign. The following items, as a minimum, s hall be included in the checklist:a.Assurance that critical plant para meters are within allowable limits (parameters and allowable limits shall be list ed on the checklist).

CALLAWAY - SP18.1-20Rev. OL-21 5/15b.Assurance of the availability and proper alignment of all systems essential to the prevention and miti gation of operational transients and accidents by a check of the control console. What to check and criteria for acceptable status shall be included in the checklist.c.Identification of systems and components that are in a degraded mode of operation permitted by the Technical Sp ecifications. 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.)2.Checklists or logs shall be prov ided for completion by the offgoing and oncoming auxiliary operators and technicians. Such checklists or logs shall include any equipment under maintenance or test that by itself could degrade a system crit ical to the prevention and mitigation of operational transients and accidents or initiate an operational tr ansient (what to check and criteria for acceptable status s hall be included on the checklist); and3.A system shall be established to evaluate the effectiveness of the shift and relief turnover procedures (for example, periodic independent verification of system alignments)."18.1.9.2UE Response Callaway Plant administrati ve procedures define specific shift relief and turnover procedures for licensed operators. Turnover checklists incl ude the following information:a.Means to assure that critical plant parameters are within allowable limits.b.Means to assure the availability and proper alignment of all safety-related systems.c.Means to identify any activities impacting Technical Specifications.d.A clear record of transfer of the command function on each shift. Additional checklists or logs are provided for operations technicians (or assistant operations technicians) to re cord any safety-related equi pment in a degraded mode or that in a state of operation which could initiate an operational transient involving safety-related equipment.The adequacy of shift re lief and turnover procedures shal l be evaluated periodically as directed by administrative procedures.

CALLAWAY - SP18.1-21Rev. OL-21 5/1518.1.9.3Conclusions Union Electric has satisfied NRC guidance relative to shif t relief/turnover procedures through commitments contained in administrative procedures.18.1.10SHIFT MANAGER'S RESPONSIBILITIES (I.C.3)

This item is discussed in Section 18.1.2, Shift Manager Admini strative Duties.18.1.11CONTROL ROOM ACCESS (I.C.4)18.1.11.1NRC Guid ance Per NUREG-0578 Position The licensee shall make provisions for limiting access to the control r oom to those individuals responsible for the direct operation of the nuclear power plant (E.G., operations supervisor, shift manager, and control room operators), to technical advisors who may be requested or required to support the operation, and the predesignated NRC personnel. Provisions shal l include the following:1.Develop and implement an administrative procedure that establishes the authority and responsibility of the person in charge of the control room to limit access.2.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 c harge of the contro l room shall be established and limited to persons posse ssing a current senior reactor operator's license. The plan shall clearly define the lines of communication and authority for plant management pers onnel not in dire ct command of operations, including those who report to stations outside the control room."18.1.11.2Union Electric Response Union Electric has developed an administrative procedure which includes limitations on access to the control room. In addition to the access control provisions available via the plant security systems, other restrictions are imposed by administrative procedures.

During normal operations, acce ss is limited to those indi viduals whose presence is necessary to carry out assigned functions.

In an emergency situat ion, access to the control room shall be limited by the Shift Manager to the operating shift complement, EDO, Plant Director; Director, Nuclear Operations; Ma nagers, Operations; one NRC representative, and addi tional management and support personnel deemed necessary to effectively handl e the situation.

CALLAWAY - SP18.1-22Rev. OL-21 5/15 Union Electric provides admi nistrative procedures which define the line-of-command in the control room. The Shift M anager is in overall command of the plant. Union Electric provides administrative proc edures which define lines of communicat ion and authority for Callaway Plant management "who report to stations both within and outside the control room."18.1.11.3ConclusionsUnion Electric has established a procedure which clearly defi nes the line of authority in the control room during nor mal and emergency situations. In addition, UE has established a procedure that cl early defines restrictions on control room access during normal and emergency condition

s. These procedures comp ly with the NRC guidance specified in NUREG-0578.18.1.12PROCEDURES FOR FEEDBACK OF OPER ATING EXPERIENCE TOPLANT STAFF (I.C.5)18.1.12.1NRC Guidance Per NUREG-0737 PositionIn accordance with Task Acti on Plan I.C.5, Procedures for Feedback of Operating Experience to Plant Staff (NUREG-0660), each applicant fo r an operating license shall prepare procedures to ensur e that operating information pertinent to plant safety originating, both within and outside the utili ty organization is c ontinually supplied to operators and other personnel and is incorporated into training and retraining programs.

These procedures shall:1.Clearly identify organiza tional responsibilities fo r review of operating experience, the feedback of pertinent information to operators and other personnel, and the incorporation of su ch information into training and retraining programs;2.Identify the admi nistrative and technical review steps necessary in translating recommendations by t he operating experience assessment group into plant actions (e.g., changes to procedures, operating orders);3.Identify the recipients of various cate gories of informat ion from operating experience (i.e., supervisory personnel, shift technical advisors, operators, maintenance personnel, and health ph ysics technicians) or otherwise provide means through which such information can be readily related to the job functions of the recipients;4.Provide means to ensure that af fected personnel become aware of and understand information of sufficient importance that shoul d not wait for emphasis through r outine training and re training programs; CALLAWAY - SP18.1-23Rev. OL-21 5/155.Ensure that plant personnel do not routinely receive extraneous and unimportant information on operating experience in such volume that it would obscure priority in formation or otherwise det ract from overall job performance and proficiency;6.Provide suitable checks to ensure that conflicting or contradictory information is not conveyed to operators and other personnel until resolution is reached; and7.Provide periodic internal audit to ensure that t he feedback program functions effectively at all levels.Clarification Each utility shall carry out an operating experience assessment function that will involve utility personnel having co llective competence in all areas important to plant safety. In connection with this assessment function, it is important t hat procedures exist to ensure that important information on operating exper ience originating both within and outside the organization is continually provided to operators and other pers onnel and that it is incorporated into plant ope rating procedures, traini ng, and retraining program.Those involved in the assessment of operating experience will review information from a variety of sources.

These include operating information from the licensee's own plant(s), publications such as IE bulle tins, circulars, notices, and pertinent NRC or industrial assessments of operating experi ence. In some cases, information may be of sufficient importance that it must be dealt with promptly (through instructions, changes to operating and emergency procedures, i ssuance of special changes to operating and emergency procedures, issuance of special precautions, etc.) and must be handl ed in such a manner to ensure that oper ations management per sonnel would be directly involved in the process. In many other cases, however, important information will become available which should be brought to t he attention of operators a nd other personnel for their general information to ensure continued safe pl ant operation. Since the total volume of information handled by the assessment group may be large, it is important that assurance be provided that high-priority matters are dealt with promptly and that discrimination is used in the feedback of other informati on so that personnel are not deluged with unimportant and extr aneous information to the detriment of their overall proficiency. It is import ant, also, that technical revi ews be conducted to preclude premature dissemination of conflicting or contr adictory information."18.1.12.2Union Electric Response The Superintendent, Performance Improvement is responsible for the review, evaluation and dissemination of operating experience.

CALLAWAY - SP18.1-24Rev. OL-21 5/1518.1.12.3Conclusion Union Electric's internal programs and procedure for the review, evaluation, and dissemination of operating ex perience gained at Callaway Pl ant and at ot her operating facilities fulfil l the NRC's NUREG-0737 guidance relative to feedback and evaluation of operating experience.18.1.13VERIFY CORRECT PERFORMANCE OF OPERATING ACTIVITIES(I.C.6)18.1.13.1NRC Guidance Per NUREG-0737 Position It is required (from NUREG-0660) that licensees' procedur es be reviewed and revised, as necessary, to ensure that an effective system of verifying the co rrect performance of operating activities is provi ded as a means of reducing hum an errors and improving the quality of normal operations.

This will reduce the frequency of occurrence of situations that could result in or contribute to accidents. Such a verification system may include automatic system status m onitoring, human veri fication of operati ons and maintenance activities independent of th e people performi ng the activity (see NUREG-0585, Recommendation 5), or both.Implementation of automatic st atus monitoring, if required, will reduce the extent of human verification of operati ons and maintenance activities but will not eliminate the need for such verification in all instances. The procedures adopted by the licensees may consist of two phases--one before and one after installation of automatic status monitoring equipment, if required, in accor dance with Item I.D.3.Clarification

Item I.C.6 of the U.S. Nu clear Regulatory Commission Task Action Plan (NUREG-0660) and Recommendation 5 of NUREG-0585 propose requiring that licensees' procedures to be reviewed and revised, as necessary, to ensure that an effe ctive system of verifying the correct performance of oper ating activities is provided. An acceptable program for verification of operating activities is described below. The American Nuclear Society had prepared a draft revision to ANSI Standard N18.7-1972 (ANSI 3.2), "Admin istrative Controls and Qu ality Assurance For the Operational Phase of Nuclear Power Plants." A second proposed revision to Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operation)," which is to be issued for public comment in the near future, will endorse the latest draft revision to ANSI

3.2 subject

to the following supplemental provisions.1.Applicability of the guidance of Sect ion 5.2.6 should be extended to cover surveillance testing in addition to maintenance.

CALLAWAY - SP18.1-25Rev. OL-21 5/152.In lieu of any designated senior r eactor operator (SRO), the authority to release systems and equipm ent for maintenance or surveillance testing or return-to-service may be delegated to an on-shift SRO, provided provisions are made to ensure that the shift mana ger is kept fully informed of system status.3.Except in cases of significant radiation exposure, a second qualified person should verify correct implementation of equipment control measures, such as the tagging of equipment.4.Equipment control procedures should in clude assurance th at control room operators are informed of changes in equipment status and the effects of such changes.5.For the return-to-service of equipment important to safety, a second qualified operator should ve rify proper system alig nment unless functional testing can be performed without compromising plant safety, and can prove that all equipment, valves , and switches involved in the activity are correctly aligned.Note:A licensed operator possessing knowledge of the system s involved and the relationship of the systems to plant safety 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 stat us 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 reduced. However, the need for such verification will not be eliminated in all instances.18.1.13.2Union Electric Response UE has developed procedures which ensure an effective system of verifying correct performance of Callaway's ope rating activities. These procedures were reviewed for applicability to this section of NUREG-0737 (I.C.6). Procedures addressing the return to service of safety-related equi pment require two authorized personnel initials verifying system alignment unless functional testing can be performed without compromising plant safety.Administrative procedures address the tr ansfer of operating in formation from the off-going to the on-going shift personnel to ensure that status of equipment is understood. In addition, UE complies with the reco mmendations of R egulatory Guide 1.33 as discusse d in the OQAM.

CALLAWAY - SP18.1-26Rev. OL-21 5/1518.1.13.3ConclusionUnion Electric's administrative controls for performance of operating activities satisfy the guidance of NUREG-0737, Item I.C.6.18.1.14NSSS VENDOR REVIEW OF PROCEDURES (I.C.7)18.1.14.1NRC Guidance Per NUREG-0660"Applicants for near-term operat ing licenses will be required to obtain NSSS vendor review of their lo w-power and power-ascension test , and emergency procedures as a further verification of t he adequacy of the procedures."18.1.14.2Union Electric ResponseSpecific low-power, ascension, and em ergency procedures were reviewed by Westinghouse to provide further verification of their adequacy.18.1.14.3ConclusionUnion Electric's actions with regards to the Westinghouse review of selected procedures comply with the gui dance of NUREG-0737.18.1.15PILOT MONITORING OF SELE CTED EMERGENCY PROCEDURES FOR NEAR-TERM OPERATING LICENSE APPLICANTS (I.C.8)18.1.15.1NRC Guidance Per NUREG-0737 Position The NRC will conduct an interdisciplinary and interoffice audit of selected plant emergency operating procedures (e.g., small-break LOCA, loss of feedwater, restart of engineered safety features fo llowing a loss of ac power, steamline break, or steam-generator tube rupture).

The licensee should correct, bef ore full-power op eration, any deficiencies in the emergency procedures, as necessary, based on the NRC audit.18.1.15.2Union Electric Response NRC has conducted an in depth review of the WOG guidel ines (as discussed in Section 18.1.8.1). Since UE ag reed to use the WOG guidelines, this item is considered closed.

CALLAWAY - SP18.1-27Rev. OL-21 5/1518.1.16CONTROL ROOM DE SIGN REVIEW (I.D.1)18.1.16.1NRCGuidancePerNUREG-0737 Position In accordance with Task Action Plan I.D.1, Cont rol Room Design Reviews (NUREG-0660), all licensees and applicants for operating 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 Office of Nuclear Reactor R egulation (NRR) requir es that those applicants for operating licenses who are unable to complete this revi ew prior to the issuanc e of a license make preliminary assessments of t heir control rooms to identify significant human factors and instrumentation problems and establish a schedule approved by the 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.Clarification

NRR is presently developing human engineering guidelines to assist each licensee and applicant in performing detailed control room review. A draft of the guidelines has been published for public comment as NUREG/CR-1580, "Human Engineering 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, review ing, and incorporating substantive public comments from operating reactor licensees, applicants for operating licenses, human factors engineering experts, and other interested part ies. NRR will issue evaluation criteria, by July 1981, which will be used to judge the acceptability of the detailed reviews performed and the design m odifications implemented.Applicants for operating licenses who will be unable to complete the detailed control room design review prior to the issuance of a licens e are required to perform a preliminary control room design assessment to identify significant human factors problems. Applicants will find it of value to refer to draft document NUREG/CR-1580, "Human Engineering Guide to Control Room Evaluation," in perform ing the preliminary assessment. NRR will evaluate the applicants' preliminary assessments, 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:1.The adequacy of information presented to the operator to reflect plant status for normal operation, anticipated operational occurrences, and accident conditions.2.The groupings of displays and the layout of panels.

CALLAWAY - SP18.1-28Rev. OL-21 5/153.Improvements in the safety monito ring and human factor s enhancement of controls and control displays.4.The communications from the control room to points outside the control room, such as the onsite technical support center, remote shutdown panel, and offsite telephone lines, and to other areas within the plan t, for normal and emergency operation.5.The use of direct rather than derived signals for the presentation of process and safety information to the operator.6.The operability of the plant from the control room with multiple failures of nonsafety-grade and nonseismic systems.7.The adequacy of operati ng procedures and operator training with respect to the limitations of instrumentation displays in the control room.8.The categorization of alarms, with unique definition of safety alarms.9.The physical location of the Shift Supervisor's office, either adjacent to or within the control room complex.

Prior to the onsite review/audi t, NRR will r equire a copy of the applicant's preliminary assessment and additional informatio n, which will be used in formulating the details of the onsite re view/audit. 18.1.16.2UnionElectricResponseRefer to the following documentation:

SLNRC 81-51, dat ed June 26, 1981 SLNRC 82-016, dat ed March 16, 1982 SLNRC 83-063, dated November 30, 1983 SLNRC 84-019, dat ed February 2, 1984 SLNRC 84-048, dat ed March 21, 1984ULNRC-822, dated May 15, 1984 ULNRC-855, dated June 29, 1984 SLNRC 84-121, dat ed October 10, 1984 SLNRC 84-134, dated December 21, 1984SLNRC 85-11, dated April 1, 1985 SLNRC 85-12, dat ed April 26, 1985 SLNRC 85-16, dat ed May 24, 1985 Callaway SSER #3 I.D.1, p.22-3, 4, 5 Callaway SSER #4 I.D.1, p.22-1, 2, 3, 4, 5, 6, 7 CALLAWAY - SP18.1-29Rev. OL-21 5/15The Callaway Control Room Design Review was accepted by the NR C by letter dated August 27, 1985-B.J. Youngblood to D.F. Schnell.18.1.16.3Conclusions Based on the DCRDR activities and the NRC staff review results as detailed above, Union Electric acceptably complies with the regulatory requirements for control room design review.18.1.17PLANT SAFETY PARAMETER DISPLAY SYSTEM (I.D.2)18.1.17.1NRCGuidancePerNUREG-0696 The purpose of the safety para meter display system (SPDS) is to as sist control room personnel in evaluating the safety status of the plant.

The SPDS is to provide a continuous indication of plant parameters or derived variables representative of the safety status of the plant. T he primary function of the SPDS is to aid the operator in the rapid detection of abnor mal operating conditions. The f unctional criteria for the SPDS presented in this section are applicable for use only in the control room.

It is recognized that, upon t he detection of an abnormal plant status, it may be desirable to provide additional informa tion to analyze and diagnose the cause of the abnormality, execute corrective actions, and monitor plant response as secondary SPDS functions.

As an operator aid, the SPDS se rves to concentrate a minimum set of plant parameters from which the plant safety status can be assessed. The grouping of parameters is based on the function of enhancing the operator's capability to assess plant status in a timely manner without surveyin g the entire control room. However, the assessment based on SPDS is likely to be followed by confirmatory surveys of many non-SPDS control room indicators. Humanfactors engineering shal l be incorporated in the various aspects of the SPDS design to enhance the functional effectiveness of control room personnel. The design of the primary or principal display format shall be as simple as possible, consistent with the required function, and shall include pattern and coding techniques to assist the operator's memory recall for the detec tion and recognition of unsafe operating conditions. The human-factor ed concentration of these signal s shall aid the operator in functionally comparing signals in the assessment of safety status. All data for display shall be validated where practicable on a realtime basis as part of the display to control room personnel. For example, redundant sensor data may be compared, the range of a parameter may be compared to predetermined limits, or other quantitive methods may be used to compare values. When an unsuccessful validation of data occurs, the SPDS shall contain means of identifying the impacted parameter(s).

Operating procedures and operat or training in the use of the SPDS shall contain information and provide guidance for the resolution of unsuccessful data validation. The CALLAWAY - SP18.1-30Rev. OL-21 5/15objective is to ensure that the SPDS presents the most current and accurate status of the plant possible and is not compromised by unidentified faulty processing or failed sensors.

The SPDS shall be in operation during norm al and abnormal operati ng conditions. The SPDS shall be capable of displaying pertinent information during steady-state and transient conditions. The SPDS shall be capable of present ing the magnitudes and the trends of parameters or derived variables as necessary to allow rapid assessment of the current plant status by control room personnel. The parameter trending display shall cont ain recent and current magnitudes of the parameter as a function of ti me. The derivation and presentation of parameter trending during upset conditions is a ta sk that may be autom ated, thus freeing the operator to interpret the trends rather th an generate them. Display of time derivatives of the parameters in lieu of trends to both opti mize operator-proce ss communication and conserve space may be acceptable. The SPDS may be a source of information to other systems, and the functional criteria of these systems shall state the required interfaces with the SPDS. An y interface between the SPDS and a safety system shall be isolated in acco rdance with t he safety system criteria to preserve channel independence and ensure the integrity of the safety system in the case of SPDS malfuncti on. Design provisions shall be included in the interfaces between the SPDS and nonsafety systems to ensure the integrit y of the SPDS upon failure of nonsafety equipment. A qualification program shall be established to demonstrate SPDS c onformance to the functional criteria of this

[NUREG-0696]

document. 18.1.17.2UnionElectricResponse Supplement 1 to NUREG-0737 (Generic Letter 82-33, dated December17,1982) provided guidance and requirements for th e SPDS which super seded previous NRC guidance.A detailed description of the SP DS conceptual design, along with some of the details of the Emergency Response Facility Information System , was provided to the NRC in SLNRC 81-38 dated June 1, 1981. Further det ails were provided to the NRC in SLNRC 83-19, dated April 15, 1983. As stated in that reference, th e SPDS was required to be fully operational prior to start-up from the first refueling.

SLNRC 84-03, dated January 13, 1984 submitted a safety analysis for the SPDS to NRC per the requirements of GL 82-33. The SPDS veri fication and validati on program completion was documented in SLNRC 84-111; dated Sept ember 5, 1984 and SL NRC 86-4, dated February 27, 1986.

In addition, ULNRC-1 288, dated April 8, 1986 was written to close out GL 82-33 and inform NRC that the emer gency response facilities and information system (which includes the SPDS) were complete.

CALLAWAY - SP18.1-31Rev. OL-21 5/15 The Callaway SPDS was acc epted by the NRC by letter dated August3,1987 - T. W. Alexion to D. F. Sc hnell. (In addition, an NRC Inspection (NRC In spection Report No. 50-483/88009, dated July19,1988) of the Callaway Emergency Response Facility found no discrepancies or open items associated with the SPDS.)On April 12, 1989, the NRC issued Generic Letter No. 89-06 which required licensees to certify that the SPDS meets the requirements of NUREG-0737, Supplement 1, taking into account the information provided in NUREG-1342. This certification was provided to the NRC via ULNRC-2034, dated July 10, 1989.

SLNRC 83-19 and ULNRC-2034 descr ibe the SPDS display c onsole being located next to main control room cons oles RL001/RL002. The SPDS display console is no longer located next to RL001/RL002. The SPDS displays are availabl e on several plant computer terminals located in the Control Room. The plant computer term inal located near RL005/RL006 has bee n designated as the primary pl ant computer terminal for SPDS displays since the primary SPDS plant computer terminal previously located next to RL001/RL002 has been eliminated.18.1.17.3Conclusions Based on the above summary of SPDS activities, t he UE SPDS design agrees adequately with the requirements established in NUR EG-0737, Supplement 1.18.1.18SPECIAL LOW POWER TESTING AND TRAINING (I.G.1)18.1.18.1NRC Guidance Per NUREG-0737 NUREG-0694, "TMI-Related Requirements for New Operat ing Licenses," requires applicants for a new operating license to define and commit to a special low-power testing program approved by the NRC staff, to be con ducted at power levels no greater than 5 percent, for the purposes of providing meaningf ul technical information beyond that obtained in the normal st artup test program and to provide supplemental training.

This requirement must be met before fuel loading.

PositionThe staff position was stated in a letter to the applicants dated November 14, 1980. This letter stated that t he program should provide for the following: "Each licensed reactor operator (RO or SRO who performs RO or SRO duties, respectively) should experience the initiati on, maintenance, and re covery from natural circulation mode, using nuclear heat to simulate decay heat.

Operators should be able to recognize when natural circulation has stabilized, and should be able to control saturation margin, RCS pressu re, and heat removal rate without exceeding specified operating limits.

CALLAWAY - SP18.1-32Rev. OL-21 5/15These tests should demonstrate the following plant characteristics: length of time required to stabilize natural ci rculation, core flow distribution, ability to establish and maintain natural circulation with or without onsite and offsite power, and the ability to uniformly borate and cool down to hot shutdown conditions, us ing natural circulation. The latter demonstration may be performed using decay heat follow ing power ascension and vendor acceptance tests, and need only to perform at those plants for which the tests has not been demonstrated at a comparable prototype plant."18.1.18.2Union Electric ResponsePartial natural circulation testing has been conducted at Callaway (on10/14/84) to insure and confirm the followin g areas are satisfied.1.Training - Each cold-licensed RO (RO or SRO who perform RO or SRO duties respectively) will participate or be simulator-tr ained in the initiation, maintenance and recovery from natural circulation mode. Operators will be able to recognize when natural circulation has stabilized and will be able to control saturation margin , RCS pressure, and heat removal rate without exceeding specified operating limits. These tests will be conducted in so far as possible to include all avail able licensed operators. All licensed operators will be trained in these same areas on the Callaway simulator.2.Testing - The tests demonstrated the following plant characteristics:

Length of time required to stabilize natural circulation, core flow distribution, ability to establish and maintain natur al circulation. The simulator has full capability of simu lating natural circul ation and utilizes actual plant data.3.Procedure Validation - These test s made maximum practical use of Callaway written plant procedures to validate the completeness and accuracy of the procedures.The Union Electric natural circulation testing requirements are based on post-Three Mile Island (TMI) regulatory posit ions and NRC Branch Technical Position RSB 5-1. In response to the post-TMI positions, Westinghouse dev eloped a special low-power test program which was approved by NRC. In accordance with t he test program, prototype natural circulation testing for 4-loop plants was perfor med at the Diabl o Canyon Plant.

The prototype testing was performed in 1985 and acceptably demonstrated plant characteristics important to plant shutdown under natural circulation conditions, such as, length of the time to achieve natural circul ation, the ability to bo rate the reactor coolant system under natural circulat ion conditions and the ability to cool the plant down and depressurize under natural circ ulation conditions. The Diablo Canyon test results have been determined to be applicable to the Callaway design.

CALLAWAY - SP18.1-33Rev. OL-21 5/1518.1.18.3Conclusion The Union Electric testing (ETT-ZZ-09240) and training program meets Item I.G.1 of NUREG-0737.

CALLAWAY - SP18.2-1Rev. OL-21 5/1518.2SITINGANDDESIGN18.2.1POST-ACCIDENT REACTOR COOLANT SYSTEM VENTING (II.B.1)18.2.1.1NRCGuidancePerNUREG-0737 PositionEach applicant and licensee shall install reactor coolant system (RCS) and reactor vessel head high point vents remotely operated from the control ro om. Although the purpose of the system is to vent noncondensible gases from the RCS which may inhibit core cooling during natural circulation, the vents must not lead to an unacceptable increase in the probabili ty of a loss-of-cool ant accident (LOCA) or a challenge to containment integrity. Since these vents form a part of the reac tor coolant pressure boundary, the design of the vent s shall conform to the requirements of Appendix A to 10 CFR Part 50, "General Design Criteria." The vent system shall be designed with sufficient redundancy that ensures a low pr obability of inadvertent or irreversible actuation.

Each licensee shall provid e the following informatio n concerning the design and operation of the high point vent system: (1)Submit a description of the design, location, size, and power supply for the vent system along with results of analyses for loss-of-coolant accidents initiated by a break in the vent pipe. The results of the analyses should demonstrate compliance with the acceptance criter ia of 10 CFR 50.46. (2)Submit procedures and supporting analysis for operator use of the vents that also include th e information available to t he operator for initiating or terminating vent usage. ClarificationA.General(1)The important safety function enhanced by this venting capability is core cooling. For events beyond the present design basis, this venting capability will substantially increase the plant's ability to deal with large quantities of noncondensible gas which coul d interfere with core cooling. (2)Procedures addressing the use of the reactor coolant system 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 substantia l 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 CALLAWAY - SP18.2-2Rev. OL-21 5/15normal 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 crit ical issue. The desired venting capability can be achieved with vents in a fairly broad spectrum of sizes. The criteria for sizing a vent can be developed in several ways. One approach, which may be c onsidered, is to s pecify a volume of noncondensible gas to be ve nted and in a specific venting time. For containments particularly vulnerabl e to failure from large hydrogen releases over a short per iod of time, the necessi ty and desirability for contained venting outside the containment must be considered (e.g., into a decay gas collection an d storage system). (4)Where practical, the reactor coolant system vents should be kept smaller than the size correspon ding to the definition of LOCA (10 CFR 50, Appendix A). This will minimize t he challenges to t he emergency core cooling system (ECCS) since the inad vertent opening of a vent smaller than the LOCA definition would not require ECCS actuati on, although it may result in leakage beyond technical specification limits. On PWRs, the use of new or existing lines whose smallest orifice is larger than the LOCA definition will requi re a valve in series with a vent 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 positi on should be provided in the control room. (6)The reactor coolant vent system shall be operable from the control room. (7)Since the reactor cool ant system vent will be part of the reactor coolant system pressure boundary, all requirements for the r eactor pressure boundary must be met, and, in addition, suffic ient redundancy should be incorporated into the design to mini mize the probability of an inadvertent actuation of the system. Administrative procedures may be a viable option to meet the si ngle-failure criterion. For vents larger than the LOCA definition, an analysis is required to demonstrate compliance with 10CFR 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 emergen cy bus. A single failu re within the power and control aspects of the reactor cool ant vent system should not prevent 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.

CALLAWAY - SP18.2-3Rev. OL-21 5/15(9)Vent paths from the pr imary system to within containment should go to those areas that prov ide good mixing with containment air. (10)The reactor cool ant vent system (i.e., vent valves, block valves, position indication devices, cable terminations, and piping) shall be seismically and environmentally qualified in acco rdance with I EEE 344-1975 as supplemented by Regulatory Guide 1.

100, 1.92 and SEP 3.92, 3.43, and 3.10. Environmental qualifications are in accordance with the May23, 1980 Commission Order and Me morandum (CLI-80-21). (11)Provisions to test for operability of the reactor coolant vent system should be a part of the design. Testing should be perfo rmed in accordance with subsection IWV of SectionXI of the ASME Code for CategoryB valves. (12)It is important that the displays and controls added to the control room as a result of this requirem ent not increase the potential for operator error. A human-factor analysis should be performed taking into consideration: (a)The use of this information by an operator during both normal and abnormal plant conditions.(b)Integration into em ergency procedures. (c)Integration into operator training.

(d)Other alarms duri ng emergency and need for prioritization of alarms. B.PWRVentDesignConsiderations(1)Each PWR licensee should provide the capability to vent the reactor vessel head. The reactor vessel head vent should be capable of venting noncondensible gas from the reactor vessel 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 capabili ty 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 thous ands of tubes in a U-tube steam generator; however, the staff believes that a procedure can be developed that ensures that 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 incor porate this consideration.

CALLAWAY - SP18.2-4Rev. OL-21 5/15(3)Venting of the pr essurizer is required to ensure its availabili ty for system pressure and volume control. These are important considerations, especially during natural circulation. 18.2.1.2UnionElectricResponseThe Callaway design provides the capability of venting the RCS to ensure that, if noncondensible gases become present in t he RCS, regardless of the means postulated for generation of such noncondensibles, gases can be vented from the system, thereby ensuring that the flow paths associated with natural circulation core cooling capability are maintained. The venting capability is provided by the existing redundant pressurizer power-operated relief valves (PORVs) and th eir associated moto r-operated isolation valves which can be used for th e venting of the pressurize r and by the reactor vessel head vent system which provides redundant venting capability of the reactor vessel, RCS hot leg piping, and RCS cold leg piping via bypass leakage paths to the vessel head. The design features of these systems are discussed below. The capability for venting of the pressuri zer and the reactor ve ssel head is provided via safety grade, Class 1E, environmentally qualified, seismic Category I, redundant systems, which meet the singl e failure criteria assuri ng both vent opening and vent closing capabilities. Block valves are an integral part of both the pressurizer and reactor vessel head vent system and meet the same qualification requirements as the vent valves. The size of the RCS vents is determined as follows:1.The pressurizer vent was based on the existing PORV (3-inch valve) capabilities. 2.The reactor vessel head vent system incorporates a 3/8-inch orifice to limit the maximum reactor coolan t flow rate to a value less than that which defines a LOCA (see Figure 18.2-1). The design provides for a moto r-operated isolation valve in series with each pressurizer PORV. These PORV isolation valves are remotely actuated from the control room.

Control room indication is provided for the pressurizer PORVs and PORV isolation valves and for the reactor vessel head vent valves. Each vent is remotely operable from the control room. An i ndividual handswitch is prov ided for each valve.

The design of the RCS venti ng systems minimizes the probability of an inadvertent opening and consequence of such an opening. 1.The pressurizer vent system:The pressurizer PORVs are normally closed, Class 1E solenoid valves that energize to open. Thus, loss of power will not actuate thes e valves. The CALLAWAY - SP18.2-5Rev. OL-21 5/15PORV isolation valves are normall y open, motor-operated valves.

Assuming an inadvertent opening of the PORV or its failure to close, operator action is taken to close the associated block valve. 2.The reactor vess el head vent system:

Each of the redundant vent paths off of the reactor vessel head contains two in-series, normally closed, same safety train, Class 1E, environmentally qualified solenoid valves. The two normally closed valves in series limit any postulated events which could result in an inadvertent opening of the vent.

The pressurizer will vent to the pressurizer relief tank.

The reactor vessel head vent system valves are located on the Integrated Head Assembly walkway above the reactor vessel. The discharge from these valves will be dire cted to the op en area of the containment above the refue ling pool. This area precl udes the potential for forming stagnant pockets of vented gases. Mixing and cooling of the vent ed gases will be accomplished using perm anent plant systems. The Westinghouse Owners Group (WOG) developed a gene ric reactor vessel head vent guideline. The SNUPPS utilities used t he generic guidance develo ped by the WOG in the development of procedures for use of the original head vent system. This generic guidance is also applied for use of the new head vent system provided by AREVA, which is of a similar design.Testing of Category B valves is performed in accordance with s ubsection ISTC of the ASME Code for Operati on and Maintenance of Nuclear Power Plants as allowed by 10 CFR 50.55a.18.2.1.3ConclusionThe Callaway design for the postaccident reactor coolant system vent system meets the applicable requirements of item II.B.1 of NUREG-0737. 18.2.2DESIGNREVIEWOFTHEPLANTSHIELDING(II.B.2)18.2.2.1NRCGuidancePerNUREG-0737 Position With the assumption of a postaccident release of radioacti vity equivalent to that described in Regulatory Guides 1.3 and 1.4 (i.e., the equivalent of 50 percent of the core radioiodine, 100 percent of the core noble gas inventory, and 1 percent of the core solids are contained in the primary coolant), each licens ee shall perform a radiation and shielding-design review of the spaces around systems that may, as a result of an accident, contain highly radioac tive materials. The design review should identify the CALLAWAY - SP18.2-6Rev. OL-21 5/15location of vital areas and equipment, such as the control room, radwaste control stations, emergency power supp lies, motor control centers, and instrume nt areas, in which personnel occupancy may be unduly limited or sa fety equipment may be unduly degraded by the radiation fields during postaccident operat ions of these systems.

Each licensee shall provide for adequate access to vital areas and protection of safety equipment by design changes, increased perm anent or temporar y shielding, or postaccident procedural contro ls. The design revi ew shall determi ne which types of corrective actions are needed for vita l areas throughout the facility. Clarification The purpose of this item is to ensure that licensees examine their plants to determine what actions can be taken over the short-term to reduce radiation levels and increase the capability of operators to control and mitigate the consequences of an accident. These actions should be taken pending conclusions resulting in the long-term degraded core rulemaking, which may resu lt in a need to consider additional sources.

Any area which will or may require occupancy to permit an operator to aid in the mitigation of or recovery from an accident is designated as a vital area. For the purposes of this evaluation, vital ar eas and equipment are not necessarily the same vital areas or equipment defined in 10 CFR 73.2 for security purposes. The security center is listed as an area to be considered as potentially vital, since access to this area may be necessary to take action to give access to other areas in the plant.

The control room, technical support center (TSC), sampling station, and sample analysis area must be included among thos e areas where access is considered vital after an accident. (See Item III.A.1.2 for discussion of the TSC and emergency operations facility.) The evaluation to determine the necessary vital areas should also include, but not be limited to, considerat ion of the post-LOCA hydrogen control system, containment isolation reset control area, manual ECCS alignment area (if any), moto r control centers, instrument panels, em ergency power supplies, security center, and radwaste control panels. Dose rate determinations need not be for these areas if they are determined not to be vital.

As a minimum, necessary modi fications must be sufficient to provide for vital system operation and for occupancy of the control r oom, TSC, sampling st ation, and sample analysis area.

In order to ensure that pers onnel can perform the necessary postaccident operations in the vital areas, the followin g guidance is to be used by licensees to evaluate the adequacy of radiati on protection to the operators: (1)SourceTerm CALLAWAY - SP18.2-7Rev. OL-21 5/15 The minimum radioactive source term should be equivalent to the source terms recommended in Regul atory Guides 1.3, 1.4, and 1.7 and Standard Review Plan 15.6.5 wit h appropriate decay times based on pl ant design (i.e., you may assume that the radioactive decay that occurs before fission products can be transported to various systems). (a)Liquid-Containing Syst ems: 100 percent of the core equilibrium noble gas inventory, 50 percent of the core equilibrium halogen inventory, and 1 percent of all others are assumed to be mixed in the reactor coolant and liquids recircul ated by residual heat removal (RHR), high-pressure coolant inje ction (HPCI), and low-pressure coolant injection (LPCI), or the equivalent of these systems. In determining the source term for re circulated, depressurized cooling water, you may assume that the water contains no noble gases. (b)Gas-Containing Systems: 100 percent of the core equilibrium noble gas inventory and 25 percent of the core equ ilibrium halogen activity are assumed to be mixed in the containmen t atmosphere. For vapor-containing lines connected to the primary system (e.g., BWR steam lines), the concent ration of radioactivity shall be determined, assuming that the activity is contained in the vapor space in the primary coolant system. (2)SystemsContainingtheSource Systems assumed in your analysis to contain high leve ls of radioactivity in a postaccident situation shoul d include, but not be limited to, containment, residual heat removal system, safety injectio n systems, chemical and volume control system (CVCS), containment spra y recirculation system, sample lines, gaseous radwaste systems, and standby gas treatment systems (or equivalent of these systems). If any of these systems or others that could contain high levels of radioactivity were excluded, you should explain why such systems were excluded. Radi ation from the leakage of systems located outside of the containment need not be considered for this analysis. Le akage measurement and reduction is treated under Item III.D.1.1, "Integrity of Systems Outside Containment Likely To Contain Radioactive Material for PWRs and BWRs." Liquid waste systems need not be included in this analysis. Modifications to liquid waste systems will be considered after comple tion of Item III.D.1.4, "Radwaste System Design Features To Aid in Accident Recovery and Decontamination." (3)DoseRateCriteria The design dose rate for personnel in a vital area should be such that the guidelines of GDC 19 will not be exceeded duri ng the course of the CALLAWAY - SP18.2-8Rev. OL-21 5/15accident. GDC19 requir es that adequate radiati on protection be provided such that the dose to personnel s hould not be in excess of 5 rem whole body, or its equivalent to any part of the body for the duration of the accident. When determining the dose to an operator, care must be taken to determine the necessary occupancy times in a specific area. For example, areas requiring continuous occupancy will require much lower dose rates than areas where minimal occupancy is required. Therefore, allowable dose rates will be based upon expected occupancy, as well as the radioactive source terms and shielding. However, in order to provide a general design objective, we are provid ing the following dos e rate criteria with alternatives to be documented on a case-by-case bases. The recommended dose rates are av erage rates in the area. Local hot spots may exceed the dose rate guidelines.

These doses are design objectives and are not to be used to limit access in the ev ent of an accident. (a)Areas Requiring Continuous Occupancy: <15 mrem/hr (averaged over 30 days). These areas will require full-time occupancy during the course of the a ccident. The control room and onsite technical support center are ar eas where continuous occupancy will be required. The dose rate for thes e areas is based on the control room occupancy factors contained in SRP6.4. (b)Areas Requiring Infrequent Access: GDC19.

These areas may require access on an irregular basis, not continuous occupancy.

Shielding should be provided to allow access at a frequency and duration estimated by the licensee. The plant radiochemical/chemical analysis laboratory, radwaste panel, motor control center, instrumentation locations, and reactor coolant and containment gas sample stations are examples of sites where occupancy may be needed often, but not continuously. (4)RadiationQualificationofSafety-RelatedEquipment The review of safety-related equipm ent which may be unduly degraded by radiation during postacci dent operation of this equipment relates to equipment inside and outsi de of the primary cont ainment. Radiation source terms calculated to determine environmental qualification of safety-related equipment co nsider the following: (a)LOCA events which completely depressurize the primary system should consider releases of t he source term (100 percent noble gases, 50 percent iodines, and 1 percent particulates) to the containment atmosphere. (b)LOCA events in which the prim ary system may not depressurize should consider the source term (100 percent noble gases, 50 CALLAWAY - SP18.2-9Rev. OL-21 5/15 percent iodines, and 1 percent particulate) to re main in the primary coolant. This method is used to determine the qualification doses for equipment in close proximity to recirculati ng fluid systems inside and outside of the containment. Non-LOCA events both inside and outside of the contai nment should use 10 perce nt noble gases, 10 percent iodines, and 0 percent particulate as a source term. The following table summariz es these considerations:18.2.2.2UnionElectricResponse The shielding design criteria used for the SNUPPS plants is in accordance with NRC Standard Review Plan 12.2 and is described in Section 12.3.2 of the FSAR. Two basic plant conditions are the bases of the shielding design, no rmal full power operation, and plant shutdown. The shield ing design objectives for thes e conditions and anticipated operational occurrences, as stated in Section 12.3.2.1 , are:a.To ensure that radiation exposu re to plant oper ating personnel, contractors, administrators, vi sitors, and proximate site boundary occupants are ALARA and within the limits of 10CFR20.b.To ensure sufficient personnel access and occupancy time to allow normal anticipated maintenanc e, inspection, and safety-related operations required for each plant equipment and instrumentation area.c.To reduce potential equipment neutron acti vation and mitigate the possibility of radiatio n damage to materials.Containment LOCA Source Term (Noble Gas/Iodine/

Particulate)

Non-LOCA High-Energy Line BreakSource Term(NobleGas/Iodine/

Particulate)Outside  %(100/50/1) in RCS  %(10/10/0)in RCSInsideLargerof (100/50/1)in containment (10/10/0)(in RCS or (100/50/1) in RCS CALLAWAY - SP18.2-10Rev. OL-21 5/15d.The control room will be sufficiently shielded, so that the dire ct dose plus the inhalation dose (calculated in Chapter 15.0) will not exceed the limits of GDC-19.Radiation zones have been established, bas ed on required per sonnel access during these plant conditions.18.2.2.2.1DesignReviewofPlantShielding18.2.2.2.1.1General The following discussion provides a description of the design review of plant shielding of spaces around systems that may contain highly radioactive ma terials as a result of an accident. Systems required to process reactor coolant outside the containment during post-accident conditions we re selected for evaluation.

The radiation and shield ing design review was performed to identify the location of vital areas and equipment such as the control room, sample station, emergency power supplies, motor control cent ers, and instrument areas, in which personnel occupancy may be unduly limited or safety equipment may be unduly degraded by the radiation fields during post-accident operations of thes e systems. Additionally, the review results ensure that adequate access to vital areas and protection of safety-related equipment are provided.

As shown in Figures18.2-2 through 18.2-11, a number of radiation zone maps and associated dose rate decay curves have been produced as a result of the design review. Radiation levels for various areas around contaminated system s for various times can be found on these maps and curves. Operators may refer to the maps and curves to apprise themselves of the lo cations of potentiall y high radiation ar eas for any time following the postulated accident. These maps and curves will be available in the critical post-accident control and support areas, e.g., control room, TS C, etc., for use following postulated DBA's.18.2.2.2.1.2Scope of Design Review18.2.2.2.1.2.1Systems E ngineering MethodologyA.Selection of Systems for Shielding Review Plant systems considered in the shield ing review are classified into the following categories:CategoryA(RecirculationSystems)

The first category of systems are those systems desi gned to mitigate a design basis loss of coolant accident and which might contain highly CALLAWAY - SP18.2-11Rev. OL-21 5/15 radioactive sources.

Such systems include t he emergency core cooling systems.For the shielding review, the ECCS systems were postulated to contain significant additional source s of radioactivity in exce ss of the orig inal plant design basis.

The following systems have been selected to ensure the radiation safety concern is adequately addressed by t he existing plant shielding design:(1)Those portions of the containment spray systems used to recirculate water from the containment sump back into the containment.(2)Those portions of th e residual heat removal systems used to recirculate water from the containment sump back into the containment.(3)Those portions of the safety in jection system used to recirculate water from the containment sump back into the containment.(4)Those portions of the chemical and volume control system (CVCS) used to recirculate water from the containment sump back into the containment.CategoryB(Extensions of Containment Atmosphere)

The second category of systems are the systems or portions of systems which would contain radioac tivity by virtue of their connection to the containment atmosphere following an accident. These systems would not be expected to contain a significant le vel of radioactive sources that are considered in this shielding review, since proper op eration of the emergency core cooling systems is expected to pr event extensive core damage. Nevertheless, such sour ces have been postulated in the following system:(1)Those portions of the post-accident containment hydrogen analyzer system external to the containment which would contain the atmosphere from the containment.(2)Those portions of the post-accident sampling system used to obtain a containment at mosphere sample.

Category C (Liquid Samples)

The third category of systems is sa mpling systems. As discussed in Section18.2.3, NUREG-0737, TaskII.B.3 requires that certain CALLAWAY - SP18.2-12Rev. OL-21 5/15post-accident liquid samples be obtained from the reactor coolant system or containment systems.

Those portions of t he sampling system which must be used to meet the intent of TaskII.B.3 were included in this shielding review.B.Radioactive Source Release FractionsPer NUREG-0737, the following release fractions were used as a basis for determining the concentrations for the shielding review:

These release fractions were applied to the total curies available for the particular chemical species (i.e., noble gas, halogens, or solid) for an equilibrium fission product invent ory for the SNUPPS core.

The release fraction for Cs was assumed to be 1percent for the purposes of this shielding review. However, a relationship was developed which related the dose rates calculated, assuming 1percent Cs, to the dose rate that would be expected if 50percent of the Cs was released to the liquid source (as recommended by Revision1 to Regulatory Guide1.89, "Qualification of Class 1E Equipment for Nuclear Power Plants"). This relationship is provided in Figure18.2-11. No noble gases were included in the containment sump liquid (SourceC) because Regulatory Guide1.7 has set this precedent in modeling liquids in the containment sump.C.Source Term Models The preceding section (B) outlines the assump tions used for release fractions for the shielding design review. However, these release fractions are only the first step in modeling the source terms for the activity concentrations in the systems under review. The important modeling parameters, decay time, and dilution volume obviously also affect any shielding analysis. The following se ctions outline the rationale for the selection of values for these key parameters.(1)Decay Time(1)Source A:Containment atmosphere-100percent noble gases, 25percent halogens(2)Source B:Reactor coolant-100percent noble gases, 50percent halogens, 1percent solids(3)Source C:Containment sump liquid-50percent halogens, 1percent solids CALLAWAY - SP18.2-13Rev. OL-21 5/15For the first stage of the shieldin g design review process, no decay time credit was used with the abov e releases. The primary reason for this was to develop a set of normalized accident radiation zone maps (i.e., no decay) that could be used as a tool by the plant staff along with a set of decay curves to quantitatively assess the plant status quickly following any abnor mal occurrence. Decay curves are provided for the containment atmosphere and containment sump liquid only. Except for areas adjacent to the containment, the sump liquid source will be the dominating contributor.(2)Dilution Volume The volume used for dilution is important, since it affects the calculations of dose rate in a linear fashion. The following dilution volumes were used with the release fractions and decay times listed above to arrive at the actual s ource terms used in the shielding reviews:(3)Associated So urces and SystemsFor the following systems, the source considered is listed. Note that normally shut valves were assumed to remain shut.(a)Containment spray system-At t he initiation of recirculation, SourceC was used.(b)Safety injection system-At the initiation of recirculation, SourceC was used.(c)Residual heat removal system-SourceC was used for sump recirculation mode.(d)Sampling system-The sources used in the shielding design review for sampling syst ems were as follows:(a)Source A:Containment free volume.(b)Source B:Reactor coolant system volume.(c)Source C:The volume of wa ter present at the time of recirculation (reactor coolant system + refueling water storage tank + accumulator tanks).

CALLAWAY - SP18.2-14Rev. OL-21 5/15Containment air sample-SourceAReactor coolant sample-SourceBContainment sump sample-SourceC(e)CVCS system-The liquid source was SourceC.18.2.2.2.1.2.2Shielding Desi gn Review MethodologyA.Analytical Shielding Techniques The previous sections outlined the rationale and assumptions used for the selection of the systems in the shielding design review, as well as the formulation of the sources for those systems. The ne xt step in the review process was to use those sources to estimate dose rates from those selected systems. The dose rates we re determined using a point-kernel computer code developed by Bechtel. This code utilizes the semi-emperical methods developed by Rockwell (Reference8) for calculating the direct gamma dose rates. To determine the dose rate contribution from the containment, QAD-CG (Reference9) was used. For corridors outside compartments, reviews were done to check the dose rate transmitted into the corri dor through the walls of adjacent compartments.

Checks were also made for any piping or equipment that could directly contribute to corridor dose rates, i.e., piping that may be running directly in the corridor or equipment/piping in a compartment that could shine directly into corridors with no attenuation through compartment walls.B.Accident Radiation Zone Maps Radiation levels are evaluated using the radiation zone maps, Figures18.2-2 through 18.2-9 , and associated decay curves, Figures18.2-10 and18.2-11 , and are considered in parallel with required operator actions.

The zone boundaries were formulated based on the follow ing rationale:

ZoneDesignationRationaleD, Zone Dose Rate Limits(Rem/hr)A-IThe first zone is consistent with the personnel radiation

exposure guidelines of Task II.B.2 of NUREG-0737 for vital areas.0 0.015 D*

CALLAWAY - SP18.2-15Rev. OL-21 5/1518.2.2.2.1.2.3Personnel Exposure Limits and MethodologyA.Access Operator actions that are required post-LOCA were reviewed to ensure that first priority safety actions can be achieved in the po stulated radiation fields. This review ensures that access is available and required operator actions can be achieved as discussed in Section18.2.2.2.1.3

.B.Personnel Radiation Exposure GuidelinesA-IIThe second zone is consistent with the personn el radiation exposure guidelines of TaskII.B.2 of NUREG-0737 for vital areas requiring infrequent access or corridors to these

areas. Such zones involve no time and moti on evaluations.

0.015 0.100A-IIIThe third zone is consistent with the personn el radiation exposure guidelines of TaskII.B.2 of NUREG-0737.

Zones in this range required that a time and motion study

be done to ensure that integrated exposure was not greater than 5Rem as given in General Design Criteria19.0.100 < 5 A-IV5 < 50A-V50 < 500A-VI500 < 5000A-VII5000 < 50,000A-VIII50,000 < 500,000 ZoneDesignationRationaleD, Zone Dose Rate Limits(Rem/hr)D*D*D*D*D*D*D*

CALLAWAY - SP18.2-16Rev. OL-21 5/15 The general basis for per sonnel radiation expos ure guidelines was 10CFR50, AppendixA, GDC

19. The following addi tional radiation limit guidelines were used to evaluate occupancy and accessibility of plant vital areas. General area dose rates were used rather than maximum surface dose rates. Contributions from all sources were considered.(1)Vital areas requiring continuous occupancyVital areas such as control room, counting room, laboratory, and the onsite technical support center were verified to ensure the direct dose rate was less than 15mr/hr. The 30day average direct radiation dose rate is less than 15mr/hr for the SAS room and the control room toilet.(2)Vital areas requiring infrequent access or corridors to these vital areas For these areas, the dose rate was verified to be less than 5R/hr except as noted in Section18.2.2.2.1.3

.18.2.2.2.1.3Results of Review The shielding design criteria and objectives have been met in the design of the Callaway Plant. These criteria and objectives have been extended to the areas designated to be the onsite Technical Support Center and the Operations Support Center, as required by the expected occupancy of these areas. The following is a discussion of the impact of a postulated LOCA or TMI-2 ty pe event on the shielding des ign and is based on the Callaway specific system design capabilities:A.LOCA Assuming a DBA LOCA wi th radiation source terms consistent with Regulatory Guides 1.4 and 1.7, plus the Cs fraction discussed in Section18.2.2.2.1.2.1 , all safety-related equipment and instrumentation will be qualified for the maximum equi pment doses associated with the time that the equipment must function. All safety-related systems operations are performed either automatically or remote manually from the control room. Operati ons within the auxiliary building are not expected following a LOCA. During the long-term recovery phase, access to sample stations in the auxiliary building may be limited. As di scussed above, the dose limitations of GDC-19 for c ontrol room operators are met.B.TMI-2 Callaway is designed to preclude events similar to the TMI-2 event. For example, the Callaway design includes reactor c oolant system high point CALLAWAY - SP18.2-17Rev. OL-21 5/15vents (as discussed in Section18.2.1) and the associated Class1E instrumentation requir ed to detect inadequate co re cooling and thus precludes the degradation of the fuel cla dding and any massive release of activity to the coolant. However, assuming that a TMI-2 event does occur, contamination of the auxiliary building is precluded by design: 1)Compliance with containment isol ation criteria is described in Section6.2.4 and Section 18.2.11 and precludes contamination of the auxiliary building by auxiliary systems, and 2)the Callaway design includes a dedicated, safety-related letdown system located tota lly within the containment which provides controlled letdown capability to the pressurizer relief tank, eliminating any operational need to contaminate the chemical and volume control system in the auxili ary building.

Based on the above, dose rates were not evaluated in the auxiliary building for an undiluted reactor coolant system source term being present in the residual heat removal system. Dose rates inside containment due to the TMI-2 type event have been considered for equipment qualification. Habitability of the TSC is addressed in Section 18.3.2.2.18.2.2.3Conclusion The shielding design criteria and objectives fo r the Callaway Plant meet the applicable recommendations of item II.

B.2 of NUREG-0737. R adiation qualification of safety-related equipm ent is addressed in Section 3.11(B)

.18.2.3POSTACCIDENT SAMPLING SYSTEM (II.B.3)18.2.3.1NRCGuidancePerNUREG-0737 Position A design and operational revi ew of the reactor coolant and containment atmosphere sampling line systems shall be per formed to determine the capability of personnel to promptly obtain (less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) a sample under accident conditions without incurring a radiation exposure to any i ndividual in excess of 3 and 18-3/4 Rem to the whole body or extremities, respectively.

Accident conditions should assume a Regulatory Guide 1.3 or 1.4 release of fission products. If the review indicates t hat personnel coul d not promptly and safely obtain the samples, additional design features or shielding should be provided to meet the criteria.

A design and operational review of the radiological spectr um analysis facilities shall be performed to determine the cap ability to promptly quantify (in less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />) certain radionuclides that are indicators of the degr ee of core damage. Such radionuclides are noble gases (which indicate cl adding failure), iodines and cesi ums (which indicate high fuel temperatures), and nonvolatile isotopes (whi ch indicate fuel me lting). The initial reactor coolant spectr um should correspond to a Regulatory Guide 1.3 or 1.4 release.

CALLAWAY - SP18.2-18Rev. OL-21 5/15 The review should also consider the effects of dire ct radiation fr om piping and components in the auxiliary building and possible contamination and direct radiation from airborne effluents. If the review indicates that t he analyses required cannot be performed in a prompt man ner with existing equipment , design modifications or equipment procurement shall be undertaken to me et the criteria.

In addition to the r adiological analyses, certain chemical analyse s are necessary for monitoring reactor conditions. Procedures shall be prov ided to perform boron and chloride chemical analyses, assuming a highly radioactive initial sample (Regulatory Guide 1.3 or 1.4 source te rm). Both analyses shall be capable of being completed promptly (i.e., the boron sample analysis within an hour and the chloride sample analysis within a shift). Clarification The following items ar e clarifications of requirements identified in NUREG-0578, NUREG-0660, or the September 13 and October 30, 1979 clarification letters. (1)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 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> or less from the time a decision is made to take a sample. (2)The licensee shall establish an onsit e radiological and chemical analysis capability to provide, within the 3-hour time frame established above, quantification of the following: (a)Certain radionuclid es in the reactor coolant and containment atmosphere that may be indicato rs of the degree of core damage (e.g., noble gases, iodines and cesi ums, and nonvolatile isotopes). (b)Hydrogen levels in the containment atmosphere. (c)Dissolved gases (e.g., H 2), chloride (time allotted for analysis subject to discussion below), and bor on concentrati on of liquids. (d)Alternatively, have inline monitoring capabilities to perform all or part of the above analyses. (3)Reactor coolant and containm ent atmosphere sampling during postaccident conditions shall not require an isolated auxiliary system [e.g., the letdown system, reactor water cleanup system (RWCUS)] to be placed in operation in order to use the samp ling system. (4)Pressurized reactor coolant samples are not required if the licensee can quantify the amount of dissolved gases with unpre ssurized reactor coolant CALLAWAY - SP18.2-19Rev. OL-21 5/15 samples. The measurement of either tota l dissolved gases or H 2 gas in reactor coolant sample s is considered adequate.

Measuring the O 2 concentration is recommended, but is not mandatory. (5)The time for a chloride analysis to be performed is dependent upon two factors: (a) if the plant

's coolant water is seawat er or brackish water and (b) if there is only a single barrier between primary containment systems and the cooling water.

Under both of the above conditions, the licensee shall provide for a chlori de analysis within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the sample being taken. For all other case s, the licensee shall prov ide for the analysis to be completed within 4 days. The chlori de analysis does not have to be done onsite. (6)The design basis for pl ant equipment for reactor coolant and containment atmosphere samplin g and analysis must assume that it is possible to obtain and analyze a sample without radiatio n exposures to any individual exceeding the criteria of GDC19 (AppendixA, 10CFRPart50) (i.e., 5 rem whole body, 75rem extremities). [Note that the desi gn and operational review criterion was changed from the operational limits of 10CFRPart 20 (NUREG-0578) to the GDC 19 criterion (October 30, 1979 letter from H.R.

Denton to all licensees).](7)The analysis of primary coolant sample s for boron is re quired for PWRs. (Note that Revision 2 of Regulatory Guide1.97, w hen issued, will likely specify the need for primary coolant boron analysis capability at BWR plants.)(8)If inline monitori ng is used for any sampling and analytical capability specified herein, the li censee shall provide ba ckup sampling through grab samples, and shal l demonstrate the capability of analyzi ng the samples. Established planning for analysis at offsite facilities is acceptable.

Equipment provided for backup sampling shall be capable of providing at least one sample per day for 7 days fo llowing onset of the accident and at least one sample per week until the accident condition no longer exists. (9)The licensee's radiologica l and chemical sample analysis capability shall include provisions to: (a)Identify and quantify the isotopes of the nuclide categories discussed above to levels corresp onding to the source terms given in Regulatory Guide 1.3 or 1.4 and 1.7.

Where necessary and practicable, the ability to dilute samples to provide capability for measurement and reduc tion of personnel exposure should be provided. Sensitivit y of onsite liquid sample analysis capability should be such as to permit measurement of nuclide concentration in the range from approximately 1mCi/g to 10 Ci/g.

CALLAWAY - SP18.2-20Rev. OL-21 5/15(b)Restrict background levels of radiation in the radiological and chemical analysis facility from s ources, such that the sample analysis will provide results with an acceptably small error (approximately a factor of2). This can be accomplished through the use of sufficient shielding around samples and outside sources, and by the use of ventilation system design which will control the presence of airborne radioactivity. (10)Accuracy, range, and sensitivity shall be adequate to provide pertinent data to the operator in order to describe t he radiological and chemical status of the reactor coolant systems. (11)In the design of the postaccident sampling and analysis capability, consideration should be given to the follow ing items: (a)Provisions for purging sample li nes, for reducing plateout in sample lines, for minimizing sample loss or distortion, for preventing blockage of sample lines by l oose material in the RCS or containment, for appropriate disposal of the samples, and for flow restrictions to limit reactor coolant loss from a rupture of the sample line. The post-accident reactor coolant and containment atmosphere samples should be representative of the reactor coolant in the core area and the cont ainment atmosphere following a transient or accident. The sample lines s hould be as short as possible to minimize the volume of fluid to be taken from containment. The residues of sa mple collection should be returned to containment or to a closed system. (b)The ventilation ex haust from the sampling st ation should be filtered with charcoal adsorbers and high-efficiency particulate air (HEPA) filters. (c)Guidelines for analytical or instrumentation range are given below in Table II.B.3-1. 18.2.3.2UnionElectricResponse WCAP-14986-A, Revision 2, 'Post Accident Sampling System Requirements: A Technical Basis,' evaluated the post accident sampling system (PASS) requirements to determine their contribution to plant safety and accident recovery. The topical report considered the progression and consequences of core damage accidents and assessed the accident progressi on with respect to plant abnor mal and emergency operating procedures, severe accident management guidance, and emergency plans. WCAP-14986 concluded that the current PASS samples specified in NUREG-0737, 'Clarification of TMI Action Plan Requirements,' may be eliminated (i.e., remove the requirements to perform the sampling fr om the licensing basis).

CALLAWAY - SP18.2-21Rev. OL-21 5/15 The NRC issued a safety evaluation dated June 14, 2000 approving WC AP-14986 with additional licensee required acti ons. Callaway Plant Lice nse amendment [144] dated

[April 6, 2001] implemented WCAP-14986 and the associated NRC safety evaluation dated June 14, 2000, which removed the program requirements of Technical Specification Sect ion 5.5.3, "Post Accident Sampling."18.2.3.3Conclusion Based on the above discussion, item II.B.3 of NUREG-0737 is no longer applicable to the Callaway Plant. 18.2.4TRAINING FOR MITIGATING CORE DAMAGE (II.B.4)18.2.4.1NRC Guidance Per NUREG-0737 Position The staff requires that the applicants develop a program to ensure that all operating personnel are trained in the use of installed plant syst ems to control or mitigate an accident in which the core is severely damaged. The trai ning program shall include the following topics:A.Incore Instrumentation(1)Use of fixed or movable incore detectors to determi ne the extent of core damage and geometry changes.(2)Use of thermocoup les in determining peak temperatures; methods for extended range readings; methods for direct readings at terminal junctions.B.Excore Nuclear Instrumentation (NIS)Use of NIS for determination of void information; void location basis for NIS response as a function of core te mperatures and density changes.C.Vital Instrumentation(1)Instrumentation response in an accident environment; failure sequence (time to failur e, method of failure);

indication reliability (actual versus indicated level).(2)Alternative methods for measuri ng flows, pressures, levels, and temperatures.(a)Determination of pressurizer level if all level transmitters fail.

CALLAWAY - SP18.2-22Rev. OL-21 5/15(b)Determination of letdown flow with a clogged filter (low flow).(c)Determination of other reactor coolant system parameters if the primary method of measurement has failed.D.Primary Chemistry(1)Expected chemistry result s with severe core damage; consequences of transferring sma ll quantities of liquid outside containment; importance of using leaktight systems.(2)Expected isotopic breakdown for core dam age; for clad damage.(3)Corrosion effects of extended immersion in primary water; time to failure.E.Radiation Monitoring(1)Response of proce ss and area monitors to severe damage; behavior of detectors when saturated; method fo r detecting radiation readings by direct measurement at detector output (over ranged detector); expected accura cy of detectors at different locations; use of detectors to determine the extent of core damage.(2)Methods of determining dose rate inside the containment from measurements taken outside the containment.F.Gas Generation(1)Methods of H 2 generation during an acci dent; other sources of gas (Xe, Kr); techniques for venti ng or disposal of noncondensibles.(2)H 2 flammability and explos ive limit, sources of O 2 in containment or reactor coolant system.18.2.4.2Union Electric Response Union Electric presents a course on mitigating core damage to licensed operators which covers the topics outlined in section 18.2.4.1. Training of Callaw ay Plant personnel to recognize and mitigate the consequences of core damage meets the intent of the Institute of Nuclear Power Operations Guidelines, Rev.1, 1/15/81.18.2.4.3Conclusion Union Electric's training pr ogram for mitigating core da mage satisfies NUREG-0737.

CALLAWAY - SP18.2-23Rev. OL-21 5/1518.2.5PERFORMANCE TESTING OF THE PRESSURIZER POWER-OPERATED RELIEFVALVE(II.D.1)18.2.5.1Background The Report of the President's Commission on the Accident at Three Mile Island, Findings A.3 and A.4, describes the ro le the failure to close the power-operated relief valve (PORV) had in the resulting accident. The Report found that failure of the valve initiated the accident, but also found that the operat ing crew and utility management failed to diagnose the occurrence and consequences of the PORV fa ilure. This latter item contributed more to the cons equences of the accident than the PORV failure to close. The NRC, in its review of t he accident at TMI-2, conclu ded that additional assurance should be provided that PORVs and safety valves will per form as designed and that indication of the status of th ese valves must also be prov ided in the control room. The first item is discussed below.

The second item is discussed in Section 18.2.6. 18.2.5.2NRCGuidancePerNUREG-0737 Position Pressurized-water reactor and boiling-water reactor licensees and applicants shall conduct testing to qualify the reactor coolant system reli ef and safety valves under expected operating conditions for design-basis transients and accidents. ClarificationLicensees and applicants shall determine th e expected valve operating conditions through the use of analyses of accidents and anticipat ed operational occurrences referenced in Regulatory Guide 1.70, Revision2.

The single failures applied to these analyses shall be chosen so that the dynamic forces on t he safety and relief valves are maximized. Test pressure s shall be the highest predict ed by conventional safety analysis procedures. Reactor coolant system relief and safe ty valve qualification shall include qualification of associated control circuitry, piping, and supports, as well as the valves themselves. A.Performance Testing of Relief and Safety Valves--The following information must be provided in report form by October 1, 1 981 for BWRs and July 1, 1982 for PWR's:(1)Evidence supported by test of safe ty and relief valve functionability for expected operating and accident (non-AT WS) conditions must be provided to NRC.

The testing should demonstrate that the valves will open and re close under the expect ed flow conditions.

CALLAWAY - SP18.2-24Rev. OL-21 5/15(2)Since it is not planned to test all valves on all plants, each licensee must submit to NRC a correlation of other evidence to substantiate that the valves tested in the EPRI (Electric Power Research Institute) or other generic test progr am demonstrate the functionability of as-insta lled primary relief and safety valves. This correlation must show that the test conditions used are equivalent to expected operating and accident condi tions, as prescribed in the Final Safety Analysis Report (FSAR). The effect of as-built relief and safety valve discharge piping on valve operability must also be accounted for, if it is different from the gener ic test loop piping. (3)Test data, including criteria for success and failure of valves tested, must be provided for NRC staff review and evaluation. These test data should include data that would permit plant-specific evaluation of discharge piping and supports that are not directly tested. B.Qualification of PWR Block Valves--Although not specifically listed as a short-term lessonslearned requirement in NUREG-0578, qualification of PWR block valves is required by the NRC Task Action Plan NUREG-0660 under task item II.D.1. It is the understanding of t he NRC that testing of several commonly used block valve de signs is already included in the generic EPRI PWR safety and relief valve testing program to be completed by July1, 1981. By means of this letter, NRC is establishing July1, 1982 as the date for verification of block valve functionability. By July 1, 1982, each PWR licensee, for plants so equipped, should provide evidence supported by test that the block or isolation valves between the pressurizer and each power-operated relief valve can be operated, closed, and opened for all fluid conditions expected under oper ating and accident conditions. C.ATWS Testing--Although ATWS testing need not be completed by July1, 1981, the test facility should be designed to accommodate ATWS conditions of approximately 3,200 to 3,500 (Service Level C pressure limit) psi and 700°F with sufficient capacity to enable test ing of relief and safety valves of the size and type used on oper ating pressurized-water reactors. 18.2.5.3DiscussionThe PORVs in the Callaway design are relied on to functi on to alleviate overpressurization that possibly could occur during startup of the reactor, during cold shutdown conditions, and they may be relied on to functi on during shut down of the reactor, assuming only safety-grade equipment is functioni ng. (These functions are described in Sections 5.2 and 5.4(A).) The PORVs are required to function to mitigate the consequences of the inadvertent ECCS actuat ion at power event. The PORVs are also designed to limit high pressure during normal operation. The description of this control function is presented in Sections 5.2 and 7.6. As discussed CALLAWAY - SP18.2-25Rev. OL-21 5/15below, operability of the PORVs will be demonstrated by prototypical testing and appropriate analyses.

The safety valves for the Callaway design ar e relied on to limit pr imary system pressure following anticipated operational transients. The design basis for the safety valves is presented in Section 5.2. The valves are required by ASME Boiler and Pressure Vessel Code to mitigate excessive pressure increases, regardless of their source. As discussed below, operability of the safety valves wa s demonstrated by prot otypical testing and appropriate analyses. 18.2.5.4UnionElectricResponse The reactor coolant system is provided with two PORVs and three code safety valves. Each PORV also has an associ ated motor-operated block valve. The PORVs for Callaway were manufactured by Crosby; the safety valves were manufactured by Crosby. These valves are included in the safety and relief valve testing program that has been develop ed by EPRI. A description of this program entitled "Program Plan for the Performance Verificati on of PWR Safety/Relief Valves and Systems," dated December13, 1979, was submitted to the NRC on December17, 1979 (letters from W.J. Cahill,Jr., Chairman of EPRI Safety and Analysis Task Force, to H.

Denton and D. Eisenhut, NRC).

A revision to this program was submitted to the NRC in July 1980. The NRC staff completed its review of this program and found it acceptable.

An interim report on these valve tests was submitted by the PWR utilities to the NRC in July 1981. A final report on these tests was provided in Reference12.

Preoperational testing of the PORVs includes monitoring the dynamic response of the relief valve discharge piping during actuation of the PORVs.

These in-plant dynamic tests will be initiated with a water-solid inlet (loop seal) at the PORVs and a steam bubble maintained in the pressurizer.

Regarding verifica tion of the block valve functionability, Callaway qualification of the block valves was provided in the letter SLNRC 82-030 on July 1, 1982.

Based on the NRC review of the submittals addressing safety valves, PORVs, PORV block valves and associated piping, Union Electric was requested to provide additional information. This info rmation was provided by SNUPPS letters dated June30,1986 (SLNRC 86-07) and Septem ber 26, 1986 (SL NRC 86-09). Addi tional supporting information was transmitted to NRC by ULNRC-1500 (dated April 24, 1987) and ULNRC-1517 (dated May 29, 1987). In a September 10, 1987 transmittal, NRC formally accepted Union Electric's response to NUREG-0737, II.D.1 contingent upon UE committing to a valve inspection after each lift involving seal water discharge. ULNRC-1681 (dated November 17, 1987) committed to either replace or inspect a valve, after lift, prior to placin g the plant back in service.

CALLAWAY - SP18.2-26Rev. OL-21 5/1518.2.5.5Conclusion The Callaway plan to demons trate the operability of the PORVs and safety valves satisfies the guidance of item II.D.1 in NUREG-0737, as discussed in the NRC Safety Evaluation Report dat ed September 10, 1987.18.2.6DIRECT INDICATION OF RELIEF AND SAFETY VALVE POSITION(II.D.3)18.2.6.1NRCRequirementPerNUREG-0737 Position Reactor coolant system relief and safety valves shall be provided with a positive indication in the control room derived from a reliable valve-position detection device or a reliable indication of flow in the discharge pipe. Clarification(1)The basic requirement is to pr ovide the operator with unambiguous indication of valve positi on (open or closed) so t hat appropria te operator actions can be taken. (2)The valve position should be indicate d in the control room. An alarm should be provided in conjuncti on with this indication. (3)The valve position indication may be safety grade. If the position indication is not safety grade, a reliable single-channel direct indication powered from a vital instrument bus may be provid ed if backup method s of determining valve position are available and are discussed in the emergency procedures as an aid to operat or diagnosis of an action. (4)The valve position indica tion should be seismicall y qualified, consistent with the component or system to which it is attached. (5)The position indication should be qualified for its appropriate environment (any transient or accident which would cause the reli ef or safety valve to lift) and in accordance with Commission Order, May23, 1980 (CLI-20-81). (6)It is important that the displays and controls added to the control room as a result of this requirem ent not increase the potential for operator error. A human-factor analysis should be performed taking into consideration: (a)The use of this information by an operator during both normal and abnormal plant conditions.

CALLAWAY - SP18.2-27Rev. OL-21 5/15(b)Integration into em ergency procedures. (c)Integration into operator training. (d)Other alarms duri ng emergency and need for prioritization of alarms. 18.2.6.2UnionElectricResponse Safety-grade position indicati on is provided for each sa fety valve and power-operated relief valve (PORV) that indicates when the valve is not in its fully closed position. The position indication is seismically and environmentally qualified.

The position indication for each valve is displayed in the control r oom, and an alarm is prov ided if any of the PORVs or safety valves is not fully closed. Other, nonsafety-related instrumentation is provided on the valve discharge piping and the pressurizer relief tank to provide an alte rnate means of assessing the status of the safety valves and PORVs (see Figure 5.1-1 , Sheet 2). 18.2.6.3Conclusion The Callaway design satisf ies the guidance of Item II.D.3 of NUREG-0737. 18.2.7AUXILIARYFEEDWATER SYSTEM RELIABILITY EVALUATION (II.E.1.1)18.2.7.1Background The initial response of the auxiliary feedwater system (AFS) at TMI-2 was interrupted by two closed block valves; one va lve in each auxiliary feedwater train. The closed valves prevented feedwater from reaching the steam generator s when the main feedwater system pumps tripped off. The Report of the President's Commission on the Accident at Three Mile Island, FindingE.5.b states: "There were deficiencies in the review, approval, and implementation of TMI-2 plant procedures."

More specifically: "(vi)Performance of surveillance tests was not adequately ve rified to be sure that the procedures were followed correctly. On the day of the accident, emergency feedwater block valves which should have been open were closed. They may have been left cl osed during a surveillance test 2days earlier."

CALLAWAY - SP18.2-28Rev. OL-21 5/15However, the Report did not fi nd that the isolatio n of the auxiliary feedwater system was a pivotal event in the accident sequence.

Since the B&W design included provisions to remove decay heat and en sure core cooling without auxiliary feedwater, the total failure of the nonsafety grade auxiliary feedwater system at TMI-2 was in fact a design basis for the design of emergency safety systems. The NRC in its review of the accident assigned more signifi cance to the failure of the auxiliary feedwater system. The NRC concluded that additional evaluation and requirements should be plac ed on the auxiliary feedwater system. These items are discussed in NUREG-0737 and are presented below. 18.2.7.2NRCGuidanceperNUREG-0737 Position - AFS EvaluationThe office of Nuclear Reacto r Regulation is requiring re-evaluation of the auxiliary feedwater (AFW) systems for all PWR operating pl ant licensees and operating license applications. This action includes: (1)Perform a simpli fied AFW system relia bility analysis that uses event-tree and fault-tree logic tech niques to determine the potential for AFW system failure under various loss-of-main-feedwater-transient conditions.

Particular emphasis is given to det ermining potential fail ures that could result from human errors, common causes, single-point vulnerabilities, and test and maintenance outages. (2)Perform a deterministic review of the AFW system using the acceptance criteria of Standard Review Plan Section10.4.9 and associated Branch Technical PositionASB10-1 as principal guidance. (3)Reevaluate the AFW system flowra te design bases and criteria.

Clarification - AFS Evaluation Operating License Applicants - Operating license applicants have been reque sted to respond to staff letters of March10,1980 (W and C-E) and April24, 1980 (B&W). These responses will be reviewed duri ng the normal revi ew process for these applications. 18.2.7.3Union Electric Response A reliability analysis of the aux iliary feedwater system (AFS) was submitted to the NRC by letter SLNRC 81-44, dated June8,1981. A comparison of the design with Standard Review Plan 10.4.9 and Branch Technical Position ASB 10-1 is provided in Section 10.4.9. An evaluation of the auxiliary feedwater system flowrate design bases and criteria was submitted by letter SLNRC 81-39, dated June 3, 1981. This reliability CALLAWAY - SP18.2-29Rev. OL-21 5/15analysis and its assumptions on AFS pump availability is separate from the deterministic analyses of Section 15.2 (See Callaway Am endment No. 168).The NRC staff reviewed the SNUPPS AFS design capabilities against the recommendations of the March 10, 1980 NRC letter (D. Ross, NRC to all pending W and C-E License Applicants) wh ich corresponds to NUREG-0737, Item II.E

.1.1. Based on this review, a confirmatory licensing issue was identified, regarding physically securing the condensate storage ta nk manual isolation valve. Th is issue was resolved prior to initial fuel load in Callaway SSER No. 3 (NUREG-0830, dated May, 1984).18.2.7.4Conclusion The Callaway design and analyses for the AFS meets the recomm endations of Item II.E.1.1 of NUREG-0737.18.2.8AUXILIARY FEEDWATER INITIA TION AND INDICA TION (II.E.1.2)18.2.8.1NRC Guidance Per NUREG-0737Position - AFS Automatic InitiationConsistent with satisfying the requirements of General Design Criterion20 of AppendixA to 10CFR Part50 with respect to the timely initiation of the auxi liary feedwater system (AFS), the following requirements shall be implem ented in the short term:(1)The design shall provi de for the automatic init iation of the AFS. (2)The automatic initiation signals and circuits shal l be designed so that a single failure will not result in the loss of AFS function. (3)Testability of the initiation signals and circuits shall be a feature of the design. (4)The initiating signals and circuits shall be powe red from the emergency buses. (5)Manual capability to initiate the AFS from the control room shall be retained and shall be implemented so that a single failure in the manual circuits will not result in the loss of system function. (6)The ac motor-driven pumps and valves in the AFS shall be included in the automatic actuation (simultaneous and/or sequential) of the loads onto the emergency buses.

CALLAWAY - SP18.2-30Rev. OL-21 5/15(7)The automatic initiating signals and circuits shall be designed so that their failure will not result in the loss of manual capability to initiate the AFS from the control room.

In the long term , the automatic initiation signals and circuits shall be upgraded in accordance with safety-grade requirements. Clarification - AFS Au tomatic Initiation The intent of this recommenda tion is to ensure a reliable automatic initiation system.

This objective can be met by providing a system which meets all the requirements of IEEE Standard279-1971.

Position - AFS Flowrate Indication Consistent with satisfying the requirements set forth in General Design Criterion13 to provide the capability in the control room to ascertain the actual performance of the AFS when it is called to perform its intended function, the following requirements shall be implemented: (1)Safety-grade indication of auxiliary feedwater flow to each steam generator shall be provided in the control room. (2)The auxiliary feedwater flow instrument channel s shall be powered from the emergency buses consistent with satisfyi ng the emergency power diversity requirements of the auxiliary feedwater system set forth in AuxiliarySystems Branch Technical Position10-1 of the Standard Review Plan, Section10.4.9. Clarification - AFS Fl owrate Indication The intent of this recommendation is to ensur e a reliable indication of AFS performance.

This objective can be met by providing an overall indication system that meets the following appropriate design principles: For Westinghouse and Combustion Engineering Plants (1)To satisfy these requirements, W and C-E plants must provide as a minimum one auxiliary feedwater flow rate indicator and one wide-range steam-generator level indicator for each steam generator or two flowrate indicators. (2)The flow indicati on system should be: (a)Environmentally qualified CALLAWAY - SP18.2-31Rev. OL-21 5/15(b)Powered from highl y reliable, battery-backed non-Class1E power source (c)Periodically testable (d)Part of plant quality assurance program (e)Capable of display on command It is important that t he displays and controls added to the c ontrol room as a result of this requirement not increase the potential for operator error. A human-factor analysis should be performed, taking into consideration: a.The use of this information by an operator duri ng both normal and abnormal plant conditions. b.Integration into em ergency procedures. c.Integration into operator training. d.Other alarms during em ergency and need for priori tization of alarms. 18.2.8.2UnionElectricResponse Automatic initiation of the AFS meets the NRC recomm endations as described in Sections 10.4.9 and 7.3.6. The AFS flowrate indication meets the NRC recommendations, as described in Section 10.4.9 and 7.5.The NRC staff reviewed the SNUPPS AFS design capabilities against the recommendations of the March 10, 1980 NRC letter (D.Ross, NRC to all pending W and C-E License Applicants) whic h corresponds to NUREG-0737, Item II.E.1.2. Based on this review, a confirmatory licensing issue was identified, regarding physically securing the condensate storage ta nk manual isolation valve. Th is issue was resolved prior to initial fuel load in Callaway SSER No. 3 (NUREG-0830, dated May, 1984). 18.2.8.3Conclusion The Callaway design and analyses for the AFS meet the reco mmendations of Item II.E.1.2 of NUREG-0737.

CALLAWAY - SP18.2-32Rev. OL-21 5/1518.2.9EMERGENCY POWER SUPPLY FOR PRESSURIZER HEATERS (II.E.3.1)18.2.9.1Background The Report to the President on the Accident at Three Mile Is land, in the Account of the Accident, speaks of the inability of the operators at TMI-2 to establis h core cooling prior to gross fuel damage.

The Report does not conclude that the pressurizer heaters were required to establish core cool ing or that they are required for natural circ ulation. The Technical Staff Analysis Re port, "Summary of Sequence of Events," AppendixB, "Significant Equipment Problems," states that the operators experienced "equipment problems that may have drawn the operators' attention away from those principal actions necessary to protect the reactor core." In particular , "throughout the sequence, the operators experienced trou ble with the pressuri zer heaters tripping.

This tripping could be attributed to grounding due to the moisture being inject ed into the reactor building during the course of the accident."

The NRC included an item in NUREG-0578 and in subsequent TMI-related documents recommending that on e of the possible pressurizer heater power s upplies include an emergency power source. The NRC's recommendation is presented below. 18.2.9.2NRCGuidancePerNUREG-0737 Position Consistent with satisfying the requirements of General Design Criteria10, 14, 15, 17, and 20 of AppendixA to 10CFR Part 50 for the event of loss of offsite power, the following positions sh all be implemented: (1)The pressurizer heater pow er supply design shall provide the capability to supply, from either the offsite power source or the emergency power source (when offsite power is not available), a predetermined number of pressurizer heaters and associated controls necessary to establish and maintain natural circulation at hot standby condition

s. The required heaters and their controls shall be co nnected to the emer gency buses in a manner that will provide redundant power supply capability. (2)Procedures and training shall be established to make the operator aware of when and how the required pressurizer heaters s hall be connected to the emergency buses. If requi red, the procedures s hall identify under what conditions selected emergency loads can be shed from the emergency power source to provide sufficient capacity for the connection of the pressurizer heaters.

CALLAWAY - SP18.2-33Rev. OL-21 5/15(3)The time required to accomplish the connection of the preselected pressurizer heater to t he emergency buses shall be consistent with the timely initiation and maintenance of natural circulation conditions. (4)Pressurizer heater motive and control power interfaces with the emergency buses shall be accomplis hed through devices that ha ve been qualified in accordance with safety-grade requirements. Clarification(1)Redundant heater capaci ty must be provided, and each redundant heater or group of heaters shou ld have access to only Cl ass 1E division power supply. (2)The number of heaters required to have access to each emergency power source is that number required to maintain natural circulation in the hot standby condition. (3)The power sources need not necessarily have the capacity to provide power to the heaters concurrent ly with the loads required for loss-of-coolant accident. (4)Any changeover of the heaters from normal offs ite power to emergency onsite power is to be accomplished manually in the control room. (5)In establishing procedure to manually load the pre ssurizer heaters onto the emergency power sources, careful consideration must be given to: (a)Which ESF loads may be appropriat ely shed for a give n situation. (b)Reset of the safety injection actuation signal to permit the operation of the heaters. (c)Instrumentation and cr iteria for operator us e to prevent overloading a diesel generator. (6)The Class 1E interfaces for main power and control power are to be protected by safety-grade circuit br eakers (see also Regulatory Guide 1.75). (7)Being non-Class 1E loads, the pressuri zer heaters must be automatically shed from the emergency power source s upon the occurrence of a safety injection actuation signal (see item 5.b. above)."

CALLAWAY - SP18.2-34Rev. OL-21 5/1518.2.9.3UnionElectricResponseThe total capacity of the pressurizer heaters at 480V ac is 1,799Kw (Table5.1-1

). The pressurizer heaters are divided into three groups (see Figure8.3-2). The rated capacity of each group at 480V ac is as follows: GroupA-692KwGroupB-692KwGroupC-415Kw The group C heaters are used for proportional control du ring power operation. Groups A and B are the backup heater groups; each of these two groups is powered from a Class 1E power source. This power is interrupted by the load shedder/sequencer following a safety injection or emergency bus undervoltage signal.

The controls for each backup pressurize r heater group are pr ovided with redundant non-Class 1E ac power sources--one from the 480-Vac system and one from the 125-Vdc system via a 125-Vdc/120-Vac inverter (see Figure 8.3-6

). Each battery charger of the 125-Vdc system is supplied from a single separation group of the 4.16-kV onsite emergency distribution system. When the 480-Va c system is unavailable following a loss-of-offsite power, the dc-backed power supplies will supply the backup pressurizer heater controls. Si milar to the breakers feeding the heater load centers, the circuit breakers supplying the 125-Vdc battery chargers ar e automatically tripped upon an SIS or emergency bus undervoltage signal. They may be reclosed from the control room when desired after reset of the breaker tr ipping signals. For additional reliability, a cr oss-tie is provided between Separation Groups 5 and 6 of the non-Class 1E 125-Vdc system. This will permit operation of selected loads of both separation groups in the event of a failure of either battery charger.

All the breakers wh ich function upon SIS and bus undervoltage are seismically qualified isolation devices. Analysis shows that subcooling would be maintained in the reactor coolant system for up to 4hours without heat input from the pressurizer heater

s. Pressure control for the reactor coolant system , as discussed in Section5.4(A), can be accomplished without pressurizer heaters. If pr essurizer heaters were used fo r pressure control, analysis indicates that 150kW is sufficient to maintain subcooling. Plan t procedures will be provided for manually connec ting (from the control room) pressurizer heaters to emergency power sources following a loss of offsite power. 18.2.9.4Conclusion The Callaway design satisfies the guida nce of item I.E.3.

1 of NUREG-0737.

CALLAWAY - SP18.2-35Rev. OL-21 5/1518.2.10DEDICATED HYDROGEN PENETRATIONS (II.E.4.1)18.2.10.1NRCGuidancePerNUREG-0737 Position Plants using external recomb iners or purge systems for post-accident combustible gas control of the containment atmosphere should provide containment penetration systems for external recombiner or purge systems that ar e dedicated to that service only, that meet the redundancy and single-failure requirements of General Design Criteria54 and 56 of AppendixA to 10CFR50, and that are sized to satisfy the flow requirements of the recombiner or purge system. The procedures for the use of combustible gas control systems following an accident that results in a degraded core and release of radioactivity to the containment must be reviewed and revised, if necessary. Clarification (1)An acceptable alternative to the dedicated penetration is a combined design that is single-failure proof for containment isolation purposes and single-failure proof for operation of the recomb iner or purge system. (2)The dedicated penetration or the combined single-fa ilure proof alternative shall be sized such that the flow requirements for the use of the recombiner or purge system are satisfied. The design shall be based on 10CFR50.44 requirements. (3)Components furnished to satisfy this requirement shall be safety grade. (4)Licensees that rely on purge systems as the primary means of controlling combustible gases following a loss-of-coolant accident should be aware of the positions taken in SECY-80-399, "Proposed Interim Amendments to 10CFR Part50 Related to Hydrogen Control and Certain Degraded Core Considerations." This proposed rule, published in the FederalRegister on October2, 1980, would require plants that do not have recombiners to have the capacity to install exter nal recombiners by January1, 1982. (Installed internal recombiners are an acceptable alternative to the above.)(5)Containment atmosphere dilution (CAD) systems are considered to be purge systems for the purpose of implementing the requirements of this TMI Task Action item.

CALLAWAY - SP18.2-36Rev. OL-21 5/1518.2.10.2UnionElectricResponse The NRC has eliminat ed the requirement for a postula ted hydrogen release associated with a design-basis LOCA from 10 CFR 50.44, and the hydrogen recombiners and purge system discussed below ar e no longer required.The postaccident H 2 control is accomplished by redundant hydrogen recombiners which are permanently installed inside the containment. Therefore, dedicated hydrogen control penetrations are not requi red, and this item is not appl icable to the Callaway Plant.As a backup to the safety-related hydrogen control system, a means of purging hydrogen from the containment is provided. Only the containment penetrations and the associated isolation valves are safety-related in the hydrogen purge system. These penetrations are not the subject of this it em, since they do not serve ex ternal hydrogen recombiners.

Since the hydrogen recombiners are actuated from the control room, the shielding and personnel exposure limitations associated with reco mbiner use and development of procedures for reduction of doses are not applicable to SNUPPS. 18.2.10.3Conclusion Item II.E.4.1 is not applic able to the Callaway Plant.18.2.11CONTAINMENT ISOLATION DEPENDABILITY (II.E.4.2)18.2.11.1NRCGuidancePerNUREG-0737 Position(1)Containment isolation system de signs shall comply with the recommendations of Standard Review Plan Section6.2.4 (i.e., that there be diversity in the parameters sensed for the initiation of containment isolation). (2)All plant personnel shal l give careful considerat ion to the definition of essential and nonessential systems, identify each system determined to be essential, identify each system determined to be nonessential, describe the basis for selection of each essent ial system, modify their containment isolation designs accordingly, and report the results of t he re-evaluation to the NRC. (3)All nonessential systems shall be automatically isolated by the containment isolation signal. (4)The design of control systems for automatic containment isolation valves shall be such that resetting the isol ation signal will not result in the CALLAWAY - SP18.2-37Rev. OL-21 5/15automatic reopening of containment isolation valves. Reopening of containment isolation valves shall require deliberate operator action. (5)The containment se tpoint pressure that initiates containment isolation for nonessential penetrations must be reduced to the minimum compatible with normal operat ing conditions. (6)Containment purge valves that do not satisfy the operability criteria set forth in Branch Technical PositionCSB6-4 or the Staff Interim Position of October23, 1979 must be sealed closed as defined in SRP6.2.4, ItemII.3.f during operational conditions 1, 2, 3, and 4.

Furthermore, these valves must be verified to be closed at least every 31days. (A copy of the Staff Interim Position [was to be] enclosed as Attachment1 [to NUREG-0737].) (7)Containment purge and vent isolation valves must close on a high radiation signal. Clarification(1)The reference to SRP6.2.4 in position1 is only to the diversity requirements set forth in that document. (2)For postaccident si tuations, each nonessentia l penetration (except instrument lines) is requ ired to have two isolation barriers in se ries that meet the requirements of General Design Criteria 54, 55, 56, and 57, as clarified by Standard Review Plan, Section6.2.4. Isolation must be performed automatically (i.e., no credit can be given for operator action).

Manual valves must be sealed closed, as defined by Standard Review Plan, Section6.2.4, to qu alify as an isolation barrier. Each automatic isolation valve in a nonessential p enetration must receive the diverse isolation signals. (3)Revision2 to Regulatory Guide1.141 will contain guidance on the classification of essential versus nonessential systems and is due to be issued by June1981. Requirements for operating plants to review their list of essential and nonessent ial systems will be issued in conjunction with this guide, including an appropriate time schedule for completion. (4)Administrative provisi ons to close all isolati on valves manually before resetting the isolation signals is not an accept able method of meeting position4. (5)Ganged reopening of containment isolation valves is not acceptable.

Reopening of isolation valves must be performed on a valve-by-valve CALLAWAY - SP18.2-38Rev. OL-21 5/15basis, or on a line-by-line basis, provided that electr ical independence and other single-failure criteria continue to be satisfied. (6)The containment pressure history during normal operat ion should be used as a basis for arriving at an appropriate minimum pressure setpoint for initiating containment isolation. The pressure setpoint selected should be far enough above the maximum observed (or expec ted) pressure inside containment during normal operation so that inadvertent containment isolation does not occur du ring normal operation from instrument drift or fluctuations due to the accu racy of the pressure sensor. A margin of 1psi above the maximum expected containm ent pressure should be adequate to account for instrument error. Any proposed values greater than 1psi will require detailed justification. Applicants for an op erating license and operating plant licensees that have operated less than oneyear should use pressure history data from similar plants that have operated more than one year, if possible, to arrive at a minimum containm ent setpoint pressure. (7)Sealed-closed purge isolat ion valves shall be under administrative control to ensure that they cannot be inadvertently opened. Administrative control includes mechanical devices to seal or lock the valve clos ed, or to prevent power from being supplied to the valve operator. Checking the valve position light in the cont rol room is an adequate me thod for verifying every 24hours that the purge va lves are closed. 18.2.11.2DiscussionThe containment isolation system and the containment isolat ion actuation are described in Sections6.2.4 , 7.3.2 , and 7.3.8. 18.2.11.3UnionElectricResponse All lines penetrating the cont ainment are identified in Figure 6.2.4-1. These figures also identify the actuation si gnal(s) for isolation of those lines requiring isolation. The logic design for containment isolation is such that resetting of the containment isolation signal will not result in the loss of containment isol ation. Once the init iating signal is reset, individual valves can be op ened from the control room, if required. Reopening of isolation valves is performed on a va lve-by-valve or line-by-line basis. The containment isolation setpoi nt pressure (Hi-1) that initiates containment isolation (CIS-A) for non-essential penet rations has been reduced to the minimum compatible with normal operating conditions. Refer to SNUPPS lett er SLNRC 84-43, dated March 15, 1984. The Technical Specifications establish a limit for containment pressure during normal operations. The Technical Specifications also contain the setpoint for Hi-1 which is based on the normal operat ion limit and instrument drift and accuracy.

CALLAWAY - SP18.2-39Rev. OL-21 5/15Table 18.2-2 identifies systems as eit her essential or nonessent ial. Essential systems are those systems required to have isolation valves open for either safe shutdown or mitigation of t he consequences of an accident.

The greatest number of lines ar e automatically isolated upon initiation of a containment isolation signal, PhaseA (CIS-A). A CIS-A is initiated when a safety injection signal (SIS) is initiated.

An SIS also initiates a feedwater isolation signal (FWIS) and a steam generator blowdown isolation si gnal (SGBSIS). The diverse parameters sensed to initiate an SIS are low steam line pressure, low pre ssurizer pressure, and high containment pressure (Hi-1).

The CIS-A logic is shown on Figure7.2-1, Sheet8.

The main steam and related li nes are automatically isolat ed upon initiati on of a steam line isolation signal (SLIS). The diverse parameters sensed to initiate an SLIS are either low steam line pressure or high negative steam pressure rate and high containment pressure (Hi-2). The SLIS logic is shown on Figure7.2-1, Sheet8.

The lines supplying component cooling water to equipment inside the containment is isolated by CIS-B. A CIS-B is initiated by high containment pressure (Hi-3). Diversity for CIS-B is provided in the logi c for manual actuation of containment spray, which, when manually actuated, also au tomatically actuates CIS-B.

The CIS-B is shown on Figure7.2-1, Sheet8. The containment purge system is isolated upon initiation of a containment purge isolation signal (CPIS). The diverse pa rameters sensed to initiate a CPIS are high containment purge exhaust radiation level or a CIS-A signal. The CPIS logic is shown in Figure7.3-1 , Sheet2. The guidelines used for post-DBA operability against required pressure differentials of containment mini-purge isolat ion valves intended for use during plant operation comply with NRC criteria. Document ation of operability was provided by Reference11. The shutdown purge system isolation va lves meet SRP 6.2.4, item II.3.f duri ng operational conditions 1, 2, 3, and

4. Furthermore, these valves are verified to be closed in accordance with NUREG-0737, Item II.E.4.2.All containment isolation valv es are provided with control sw itches on the main control board. Manual actuati on switches are provided for initia tion of CIS-A, SLIS, and CPIS.

In addition to diversity, these systems are redundant and meet safety-grade (Class1E) criteria. 18.2.11.4ConclusionThe design for the containm ent isolation system satisfies the requirements of ItemII.E.4.2 of NUREG-0737.

CALLAWAY - SP18.2-40Rev. OL-21 5/1518.2.12ACCIDENT MONITORING INSTRUMENTATION (II.F.1)18.2.12.1NRCGuidancePerNUREG-0737 Introduction Item II.F.1 of NUREG-0660 contains the following subparts: (1)Noble gas effluent radiological monitor.(2)Provisions for continuous sampling of plant effluents for post-accident releases of radioactive iodines and particulates and onsite laboratory capabilities (this r equirement was inadvert ently omitted from NUREG-0660; see Attachment 2 that follows, for position).(3)Containment high-range radiation monitor.(4)Containment pressure monitor.

(5)Containment water level monitor.(6)Containment hydrogen concentration monitor.

NUREG-0578 provided the basic requirements associated with items1 through 3 above. NRC staff letters issued to All Operating Nuclear Power Plants dated September13,1979 and October30,1979 provided cl arification of staff requirements associated with items 1 through 6 above. Attachments1 through 6present the staff position on these matters.It is important that t he displays and controls added to the c ontrol room as a result of this requirement not increase the potential for operator error.

A human factors analysis should be performed (s ee NUREG-0737,Section II.D.2), 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, d.other alarms during emergency and need for prio ritization of alarms.Attachment1NobleGasEffluentMonitor Position CALLAWAY - SP18.2-41Rev. OL-21 5/15Noble gas effluent monitors shall be installed with an extended r ange designed to function during accident conditions as well as during normal operating conditions.

Multiple monitors are considered necessa ry to cover the r anges of interest.(1)Noble gas effluent monitors with an upper range capacity of 10 5 Ci/cc (Xe-133) are considered to be practical and should be install ed in all operating plants. (2)Noble gas effluent monitoring shall be provided for the total range of concentration extending from normal conditions (as low as reasonably achievable (ALARA)) concentrations to a maximum of 10 5 Ci/cc (Xe-133).

Multiple monitors are considered to be necessary to co ver the ranges of interest. The range capacity of indi vidual monitors s hould overlap by a factor of10.Clarification(1)Licensees shall provi de continuous monitoring of high-level, post-accident releases of radioactiv e noble gases from the plant. Gaseous effluent monitors shall meet the requirements specified in Table II.F.1-1

[of NUREG-0737, presented below]. Typical plant effluent pathways to be monitored are also given in the table.(2)The monitors shall be capable of functioning both during and following an accident. System desi gns shall accommodate a design-basis release and then be capable of foll owing decreasing concentra tions of noble gases.(3)Offline monitors are not required for the PWR se condary side main steam safety valve and dump valve discharge lines. For this application, externally mounted monitors viewing the main steam line upstream of the valves are acceptable with procedur es to correct for the low energy gammas the external monito rs would not detect. Is otopic identification is not required.(4)Instrumentation ranges shall overlap to cover the entire range of effluents from normal (ALA RA) through acci dent conditions.

The design descriptio n shall include the fo llowing information.(a)System description, including:(i)Instrumentation to be used, including range or sensitivity, energy dependence or response, calibration frequency and technique, and vendor's model number, if applicable.

CALLAWAY - SP18.2-42Rev. OL-21 5/15(ii)Monitoring locations (or points of sampling), including description of methods used to ensure representative measurements and background correction.(iii)Location of instrument readout(s) and method of recording including description of t he method or procedure for transmitting or disseminating the information or data.(iv)Assurance of the capability to obtain r eadings at least every 15minutes during and fo llowing an accident.(v)The source of power to be used.(b)Description of proc edures or calculationa l methods to be used for converting instrument readings to release ra te per unit time, based on exhaust air flow and consi dering radionuclide spectrum distribution as a function of time after shutdown.TABLEII.F.1-1HIGH-RANGENOBLEGASEFFLUENTMONITORSREQUIREMENTCapability to detect and measure c oncentrations of noble gas fission products in plant gaseous effluents during and following an accident. All potential accident release paths shall be monitored.PURPOSETo provide the plant operator and emer gency planning agencies with information on pl ant releases of noble gases during and following an accident. DesignBasisMaximumRange Design range values may be expressed in Xe

-133 equivalent values for monitors employing gamma radiati on detectors or in microcuries per cubic centimeter of air at standard temperature and pressure (STP) fo r monitors employing beta radiation detectors (Note:1R/hr at 1 ft = 6.7 Ci Xe-133 equivalent for point source). Calibrations with a higher energy source are acceptable. The decay of radionuclide noble gases after an accident (i.e., the distribution of noble gases changes) should be taken into account.10 5 Ci/ccUndiluted containment exhaus t gases (e.g., PWR reactor building purge, BWR drywell purge through the standby gas treatment system).

Undiluted PWR condenser air removal system exhaust.

CALLAWAY - SP18.2-43Rev. OL-21 5/15 10 4 Ci/ccDiluted containment ex haust gases (e.g., >10:1 dilution, as with auxiliary building exhaust air).

BWR reactor building (secondary containment) exhaust air.PWR secondary containment exhaust air.

10 3 Ci/cc Buildings with systems cont aining primary coolant or primary coolant offgases (e.g. PWR auxiliary building, BWR turbine buildings).

PWR steam safety valve di scharge, atmospheric steam dump valve discharge.

10 2 Ci/ccOther release points (e.g., ra dwaste building, fuel handling/

storage buildings).REDUNDANCYNot required; monitoring t he final release point of several discharge inputs is acceptable.SPECIFICATIONS(None) Sa mpling design criter ia per ANSI N13.1.POWER SUPPLYVital instrument bus or dependable backup power supply to normal ac.CALIBRATIONCalibrate monitors using gamma detectors to Xe-133 equivalent (1 R/hr @ 1ft = 6.7 Ci Xe-133 equivalent for point source). Calibrate monitors using beta detectors to Sr-90 or similar long-lived beta isotope of at least 0.2 MeV.DISPLAYContinuous and record ing as equivalent Xe-133 concentrations or Ci/cc or actual noble gases.QUALIFICATIONThe instruments shall provide sufficiently accurate responses to perform the intended function in the environment to which they will be exposed during accidents.DESIGN CONSIDERATIONSOffline monitoring is acceptab le for all ranges of noble gas concentrations.

Inline (induct) sensors are acceptable for 10 2 Ci/cc to 10 5 Ci/cc noble gases.

For less than 10 2 Ci/cc, offline monitoring is recommended.Upstream filtration (prefiltering to remove radioactive iodines and particulates) is not required; however, design should consider all alternatives with respect to capability to monitor effluents following an accident.

CALLAWAY - SP18.2-44Rev. OL-21 5/15For external mounted monitors (e.g., PWR main steam line), the thickness of the pipe should be take n into account in accounting for low-ener gy gamma radiation.

CALLAWAY - SP18.2-45Rev. OL-21 5/15Attachment2SamplingofPlantEffluentsSampling of Plant Effluents PositionBecause iodine gaseous efflue nt monitors for the accident condition are not considered to be practical at this time, capability for effluent moni toring of radioi odines for the accident condition shall be provided with sampling conducte d by adsorption on charcoal or other media, followed by onsite laboratory analysis. Clarification (1)Licensees shall provi de continuous sampling of plant gaseous effluent for postaccident releases of radioactive iodines and part iculates to meet the requirements of the enclosed Table II.F.1-2 [from NUREG-0737, presented below]. Licensees shall also provi de onsite laboratory capabilities to analyze or measure these samples. This require ment should not be construed to prohibit design and development of radioiodine and particulate monitors to provide online sampling and analysis for the accident condition. If gross gamma radiation measurement techniques are used, then provisions shal l be made to minimize noble gas interference. (2)The shielding design basis is given in Table II.F.1-2 [of NUREG-0737]. The sampling system design sha ll be such that plant pe rsonnel could remove samples, replace sampling media, and transp ort the samples to the onsite analysis facility with radiation exposur es that are not in excess of the criteria of GDC-19 of 5-rem whol e-body exposure and 75 rem to the extremities during the du ration of the accident. (3)The design of the systems for the sampling of pa rticulates and iodines should provide for sample nozzle entry velocities which are approximately isokinetic (same velocity) with expected induct or instack air velocities. For accident conditions, samplin g may be complicated by a reduction in stack or vent effluent velocities to below design levels, making it necessary to substantially reduce sampler intake fl ow rates to achieve the isokinetic condition. Reductions in air flow may well be beyond the capability of available sampler flow controllers to maintain isokinetic conditions; therefore, the staff w ill accept flow contro l devices which have the capability of maintaining isokinetic conditions with variations in stack or duct design flow veloci ty of +/-20 percent. Further departure from the isokinetic condition need not be considered in design. Corrections fo r nonisokinetic sampling c onditions, as provided in Appendix C of ANSI 13.1-1969, may be considered on an ad hoc basis.

CALLAWAY - SP18.2-46Rev. OL-21 5/15(4)Effluent streams which may contain air with entrained water, e.g., air ejector discharge, shall have provisions to ensure that the adsorber is not degraded while providing a represent ative sample, e.g., heaters.

CALLAWAY - SP18.2-47Rev. OL-21 5/15TABLEII.F.1-2SAMPLINGANDANALYSISORMEASUREMENTOFHIGH-RANGERADIOIODINE ANDPARTICULATEEFFLUENTSINGASEOUSEFFLUENTSTREAMS SAMPLING MEDIA -Iodine >90 percent effective adsorpt ion for all forms of gaseous iodine.-Particulates >90 percent effective retenti on for 0.3 micron (m) diameter particles. SAMPLING CONSIDERATIONS -Representative sampling per ANSI N13.1-1969. -Entrained moisture in effluent stream should not degrade adsorber. -Continuous collection required whenever ex haust flow occurs. -Provisions for limiting occupational dos e to personnel incorp orated in sampling systems, in sample handlin g and transport, and in analysis of samples. ANALYSIS

-Design of analytical facilities and prep aration of analytica l procedures shall consider the desi gn basis sample. -Highly radioactive samples may not be compatible with generally accepted analytical procedures; in such cases, measurement of emissive gamma radiations and the use of shielding and distance factors should be considered in design. EQUIPMENT-Capability to collect and analyze or measure representative samples of radioactive iodines and particulates in plant gaseous effluents during and fo llowing an accident. The capability to sample and analyze for radioiodine and particulate effluents is not re quired for PWR secondary main steam safety valve and dum p valve discharge lines. PURPOSE-To determine quantitative release of r adioiodines and particulates for dose ca lculation and assessment.

DESIGN BASIS SHIELDING

ENVELOPE-10 2 Ci/cc of gaseous radioiodine and particulates, deposited on sampling media; 30 minutes sampling time, average gamma energy (E) of 0.5 MeV.

CALLAWAY - SP18.2-48Rev. OL-21 5/15Attachment3ContainmentHigh-RangeRadiationMonitor PositionIn containment radiati on-level monitors with a maximum range of 10 8 rad/hr shall be installed. A minimum of tw o such monitors that are physically separated shall be provided. Monitors shall be developed and qualified to function in an accident environment. Clarification (1)Provide two radiation monitor systems in containment which are documented to meet the requirements of Table II.F.1-3 (of NUREG-0737, presented below). (2)The specification of 10 8 rad/hr in the above position was based on a calculation of postaccident containment radiation le vels that included both particulate (beta) and photon (gamma) radi ation. A radiat ion detector that responds to both beta and gamma radiation ca nnot be qualified to post-LOCA (loss-of-coolant accident) containment environments, but gamma-sensitive instruments can be so qualified. In order to follow the course of an accident, a containment monitor that measures only gamma radiation is adequate.

The requirement was revi sed in the October 30, 1979 letter to provide fo r a photon-only measurement with an upper range of 10 7 R/hr. (3)The monitors shall be located in containment(s) in a manner which will provide a reasonable asse ssment of area radiation conditions inside the containment. The monitors shall be widely separated so as to provide independent measurements and shall "view" a la rge fraction of the containment volume. M onitors should not be pl aced in areas which are protected by massive shielding a nd should be reasonably accessible for replacement, maintenance, or calibration. Plac ement high in a reactor building dome is not recommended because of potential maintenance difficulties. (4)For BWR Mark III containments, tw o such monitoring systems should be inside both the primary containm ent (drywell) and the secondary containment. (5)The monitors are required to respond to gamma photons with energies as low as 60 keV and to provide an ess entially flat response for gamma energies between 100 keV and 3 MeV, as specified in Table II.F.1-3 of NUREG-0737. Monitors that use th ick shielding to increase the upper range will underestimate postaccident radi ation levels in containment by CALLAWAY - SP18.2-49Rev. OL-21 5/15 several orders of magnitude because of their insensitivity to low energy gammas and are not acceptable.

CALLAWAY - SP18.2-50Rev. OL-21 5/15TABLEII.F.1-3CONTAINMENTHIGH-RANGERADIATIONMONITORREQUIREMENT-The capability to detect and measur e 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 , with linear ener gy response +/-20%) for photons of 0.1 MeV to 3 MeV. Instruments 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 B, except as listed below.

SPECIAL CALIBRATIONIn situ calibration by electronic signal 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 not an acceptable position due to the possible differences after in situ installation. For high-range calibration, no adequate sources exist, so an al ternate 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.

CALLAWAY - SP18.2-51Rev. OL-21 5/15Attachment4ContainmentPressureMonitor PositionA continuous indication of containment pressure shall be provided in the control room of each operating reactor. Measurement and indication capabi lity shall include three times the design pressure of the containment for concrete, four times the design pressure for steel and -5 psig for all containments. Clarification(1)Design and qualificati on criteria are outli ned in Appendix B (of NUREG-0737).(2)Measurement and indication capability shall extend to 5 psia for subatmospheric containments. (3)Two or more instruments may be us ed to meet requirements. However, instruments that need to be switched from one scal e to another scale to meet the range requirements are not acceptable. (4)Continuous display and recording of the contai nment pressure over the specified range in the control room is required. (5)The accuracy and response time specif ications of the pressure monitor shall be provided and justified to be adequate for their intended function.

CALLAWAY - SP18.2-52Rev. OL-21 5/15Attachment5ContainmentWaterLevelMonitor PositionA continuous indication of contai nment water level shall be pr ovided in the control room for all plants. A na rrow range instrument 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 gallon capacity. For BWRs, a wide range instrument shall be pr ovided and cover the range from the bottom to 5 feet above the normal water level of the suppression pool. Clarification(1)The containment wide-rang e water level indication channels shall meet the design and qualificatio n criteria as outli ned in Appendix B (of NUREG-0737). The narrow-range channel shall meet the requirements of Regulatory Guide 1.89. (2)The measurement capabili ty of 600,000 gallons is based on recent plant designs. For older plants with smaller water capacities, licensees may propose deviations from this require ment, based on the available water supply capability at their plant. (3)Narrow-range water leve l monitors are required for all sizes of sumps but are not required in those plants that do not contain sumps inside the containment. (4)For BWR pressure-suppression containments, the emergency core cooling system (ECCS) suction line inlets may be used as a starting reference point for the narrow-rang e and wide-range water leve l monitors, instead of the bottom of t he suppression pool. (5)The accuracy requirements of the wa ter level monitors shall be provided and justified to be adequate for their intended function.

CALLAWAY - SP18.2-53Rev. OL-21 5/15Attachment6ContainmentHydrogenMonitor Position A continuous indication of hydr ogen concentration in the containment atmosphere shall be provided in the control room. Measurement capability shall be provided over the range of 0 to 10 percent hydrogen concentra tion under both posit ive and negative ambient pressure. Clarification(1)Design and qualification criteria ar e outlined in App endix B (of NUREG 0737).The continuous indication of hydrogen concentration is not required during normal operation. (2)If an indication is not available at all times, cont inuous indication and recording shall be functioning within 30 minutes of the initiation of safety injection. (3)The accuracy and placem ent of the hydrogen moni tors shall be provided and justified to be adequate for their intended function.

CALLAWAY - SP18.2-54Rev. OL-21 5/1518.2.12.2UnionElectricResponseRadiological Noble Gas Effluent Monitors The Callaway design provides a wide range noble gas radiatio n monitor for each of the release paths listed below. Each monitor will include detectors covering the range shown below:

The locations of these monitors are shown on Radiation Zone Drawing Figure12.3-2 , Sheet4. Separate monitoring capability for the condenser air re moval system is not provided because this system exhausts through the plant vent. The SNUPPS design includes gamma detectors to monitor the pl ume from the main steam power-operated relief valves and to monitor the steam discharge from th e turbine-driven auxiliary feedwater pump. Addi tional information on this monitoring system is provided by Reference10.

Continuous indication is provided in the control room for each monitor.

Each monitor is recorded in t he control room.

The system/methods for monitori ng and analysis are described in Reference10. The readouts from the wide range monitors are input to the plant computers. This information is accessible from the tec hnical support center and the emergency operations facility. The procedures used to calibrate the instruments and calcul ate release rates have been incorporated into the Ca llaway Plant procedures.

The following additional information was provided by Reference10.a.System description information, including energy dependence or response, range and sensitivity with respect to Xe-133, vendor model number, and methods used to assure representative measurements and background correction. b.The calculational methods or proc edures to be used for converting instrument readings to release rate per unit time based on exhaust air flow and considering radionuclide s pectrum distribution as a function of time after shutdown. MONITOR RANGEPlant unit vent (GT-RE-21B) 10-7 to 10+5 Ci/cc Radwaste building effluent (GH-RE-10B) 10-7 to 10+5 Ci/cc CALLAWAY - SP18.2-55Rev. OL-21 5/15 Union Electric submitted a variance request (to NUREG-0737, II.F.1, Attachment 1, Clarification 1) to manually correct the wide range gas monitor display to account for noble gas spectrum changes wi th time using the emergen cy plan procedures (See ULNRC-1393, dated October 24, 1986). Additional informati on to support this variance was submitted to NRC in ULNRC-1796, dated June 21, 1988 and ULNRC-1840, dated October5, 1988. This variance was accepted by NRC by letter dated February 1, 1989.Union Electric also submitted information on the noble gas radiation monitors concerning location and Technical Specifications in response to ver bal NRC questions (See ULNRC-1825, dated September 2, 1988). This issue is c onsidered closed by Union Electric. (Note: The Radiological and Environmental Technical Specifications were removed from the Technical Spec ifications and relocated to the Offsite Dose Calculation Manual and the Process Control Program; see ULNRC-2070, dated September 6, 1989 and Amendment 50 dated Februar y 12, 1990, to the Callaway License.)

Provisions for Continuous Sampling of Plant Effluents fo r Post-Accident Releases of Radioiodines and Particulates The design provides for continuous sampling of effluent radioiodines and particulates.

The wide range gas monitors described above include the capability to obtain grab samples. The sampling is a ccomplished by adsorption of iodi ne on charcoal filters or other media and by use of particulate filters. The sampling system criteria for all airborne monitoring systems are provided in Section 11.5.2.3.1.2 of the FSAR. After collection, laboratory analyzers can be used to quantify iodine and particulate releases. A backup power source is provided for sample collection and anal ysis equipment to ensure operation for a minimum of 7 consecutive days. The procedures for each facility discuss the methods and count ing equipment used to determine re leases. The expected doses from obtaining and counting a sample have been calculated to range between 750 and 1300 mrem for a sample at t he unit vent. These doses meet the requirement of NUREG-0737. Addi tional information regarding how the design meets the recommendations of TableII.F.1-2 and the provisions fo r approximate isokinetic sampling was provided by Reference10.

A variance request to NUREG-0737, II.F.1, Attachment 2, Clarification 3 to leave the wide range gas monitor sample nozzle sized to large to pr oduce isokinetic flow was submitted by ULNRC-1839, dated October 4, 1988. Additional info rmation to support this variance was submitted by ULNRC-2011, dated June2, 1989. This variance was accepted by NRC by lett er dated August 4, 1989.

Union Electric submitted a variance request to NUREG-0737, II.F.1, Attachment 2, Clarification 1 concerning the wide range gas monitor. Th is variance (submitted in ULNRC-1095, dated May 14, 1985) stated that UE coul d not perform empirical determination of line loss co rrection factors (iodine plat eout) for post accident iodine sampling from the unit vent wide range gas monitor. Addi tional supporting information was submitted in ULNRC-1255, dated February 10, 1986.

CALLAWAY - SP18.2-56Rev. OL-21 5/15Containment Radiation Monitors The Callaway design meets the recommendations of Table II.F.1-3. The design includes two physically separated Class 1E containment radiation m onitors. The monitors are designated as 0-GT-RE-59 and 0-GT-RE-60. The detec tors are located inside containment.

Indication is provided in the control room for each monitor, which is powered from a Class1E power source. One channel is provided with a recorder, which is powered from Class1E power sources. Each monitor has a range up to 10 8 R/hr for gamma radiation.

The monitors are sensitive down to 60 keV photons. The response of the monitors is linear (+/-20%) for energies between .1 Mev and 3 Mev. The e quipment has been seismically qualified for the location in which it is installed. The components are environmentally qualified for the environmental conditions to which they will be subjected.

Calibration of the monitors is addressed in procedures.

Additional information regarding the details of t he design is provided in Section11.5.2.3.2.4 and Reference10.

Union Electric submitted a variance request to NUREG-0737, II.F.1, Attachment 3 (See ULNRC-1441, dated January 29, 1987) from the requirement to calibrate the high range radiation monitor for at least one point per decade of range between 1 R/hr and 10 3 R/hr. By letter dated October 16, 1989 , the NRC rejected this variance request. Union Electric has committed to replace these detectors at Refuel IV with detectors that are calibrated to the requirement s of NUREG-0737.Containment Pressure Indication The Callaway design provi des a dual range, redundant, continuous indication of containment pressure with both ranges (0 to 69psig and -5 to 180 psig) indicated and recorded in the cont rol room at the same time. The extended range indicators are Class1E; the extended range recorder is isolated from the Class 1E ci rcuitry and is non-Class 1E. As a mi nimum, their range is from minus 5psig to three times the containment design pressure of 60psig. The response time of the containment pressure control room indication is 10 seconds for both the narrow and wi de-range instrument c hannels. The accura cy of both the narrow and wide range channels is +/-4percent of scale. The pressure monitor instrumentation meets the design and qual ification criteria of NUREG-0737, AppendixB in accordance with the WCAP 8587 qualific ation reference of FSAR Table3.11(B)-3. Containment Water Level Indication CALLAWAY - SP18.2-57Rev. OL-21 5/15 The Callaway design includes in the c ontrol room continuous indication of the containment water level. This instrumentation is redundant and des igned and qualified in accordance with Class 1E requirements to meet the requirements of NUREG-0737, Appendix B. A single range is used to monitor both the containm ent normal sump level and the containment water level.

The range is 13 feet, whic h covers 6 inches from the bottom of the containment norma l sump to an elevation equiva lent to 650, 000 gallons.

The upper limit of the range is greater than the maximum ca lculated water level. The accuracy of the indication is +/-4 percent. This accuracy is sufficient for the purpose of verifying that adequate water level (NPSH) is available to the pumps taking suction from the containment. The switc hover of the low pressure safety injection pumps to recirculation is accomp lished without the use of the cont ainment water le vel indication. Containment Hydrogen Concentration MonitorThe present design includes redundant safety-grade (Class 1E) containment post-LOCA hydrogen analyzers with redundant Class 1E indication provi ded in the control room.

These monitors meet the design and qualification requirements of NUREG-0737, AppendixB. The hydrogen analyzers have a range of 0-10 percent hydrogen volume and are designed to operate under minimum and maximum containment design pressure.

The hydrogen analyzers are manually initiated followi ng an event. Once initiated, they provide a continuous measurement of hy drogen concentration within 30 minutes.The sample points for the containment hydrogen monitors are in the vicinity of the intake of the containment air coolers and the post-accident water level.18.2.12.3Conclusion The Callaway design provides six additional post-accident monitors specified in NUREG-0737 for accident di agnosis and mitigation.

Callaway has developed emergency operating procedures which detail the use of each instrument specified during an accident. The Callaway design meets the inte nt of NUREG-0737 with the exception of the afor ementioned variances.

The design is consistent with the recomm endations of NUREG-0737, item II.F.1, for noble gas monitors.

The design includes features to sample plant effluents under accident conditions. The design of sampling system sa tisfies the criteria in NUREG-0737, item II.F.1. The containment radiation monitor design meets the recommendations of item II.F.1-3. The extended range containment pressure monitor design meets the recommendations of item II.F.1-4.

CALLAWAY - SP18.2-58Rev. OL-21 5/15The design for containment water level indication meets the requirements of NUREG-0737, item II.F.1-5. The design for the containm ent hydrogen monitors meet the requirements of NUREG-0737, itemII.F.1-6. 18.2.13INSTRUMENTATION FOR DETECTION OF INADEQUATE CORE COOLING(II.F.2)18.2.13.1NRCGuidancePerNUREG-0737 Position Licensees shall provide a description of any additional instrument ation or controls (primary or backup) proposed for the plant to supplement existing instrumentation (including primary coolant saturation moni tors) in order to provide an unambiguous, easy-to-interpret indication of inadequate core cooling (I CC). A description of the functional design requirements for the system shall also be included. A description of the procedures to be used with the proposed equipment, the anal ysis used in developing these procedures, and a schedule for installing the equi pment shall be provided. Clarification(1)Design of new instrumentation should provide an unambiguous indication of ICC. This may require new measurements or a synthesis of existing measurements which meet des ign criteria (item 7). (2)The evaluation is to include r eactor-water-level indication. (3)Licensees and applicants are required to prov ide the necessary design analysis to support the proposed final instrumentation system for inadequate core cooling and to evaluate the merits of various instruments to monitor water level and to monitor other para meters indicative of core-cooling conditions. (4)The indication of ICC must be unambiguou s in that it should have the following properties:(a)It must indicate the existence of inadequate core cooling caused by various phenomena (i.e., highvoid frac tion-pumped flow as well as stagnant boil-off); and,(b)It must not er roneously indicate ICC becaus e of the presence of an unrelated phenomenon. (5)The indication must give advanced wa rning of the appr oach of ICC.

CALLAWAY - SP18.2-59Rev. OL-21 5/15(6)The indication must cover the full range from normal operation to complete core uncovery. For example, water-level instrumentation may be chosen to provide advanced warning of two-phase level drop to the top of the core and could be supplemented by other in dicators such as incore and core-exit thermocouples pr ovided that the indicat ed temperatures can be correlated to provide i ndication of the existence of ICC and to infer the extent of core uncovery. Alternatively, full-range level instrumentation to the bottom of the core may be employed in co njunction with other diverse indicators such as core-exit thermocouples to preclude misinterpretation due to any inherent deficiencies or inaccuracies in the measurement system selected. (7)All instrumentation in the fi nal ICC system must be evaluated for conformance to AppendixB (to NUREG-0737), "Design and Qualification Criteria for Accident Monitoring Instrumentation," as clarified or modified by the provisions of items 8 and 9 that follow. This is a new requirement. (8)If a computer is provided to process liquid-level signals for display, seismic qualification is not requi red for the computer and associated hardware beyond the isolator or input buffer at a location accessible for maintenance following an accident. The single-failure criteria of item2, AppendixB, need not apply to the channel beyond the isolation device if it is designed to provide 99 percent avai lability with resp ect to functional capability for liquid-level display. The display and associated ha rdware beyond the isolation device need not be Class1 E, but should be energized from a high-reliability power source whic h is battery back ed. The quality assurance provisions cited in AppendixB, item 5, need not apply to this portion of the instrument ation system. This is a new requirement. (9)Incore thermocouples locat ed at the core exit or at discrete axial levels of the ICC monitoring system and which are part of the monitoring system should be evaluated for conformity with Attachment1, "Design and Qualification Criteria for PWR Inco re Thermocouples," which is a new requirement. (10)The types and locations of displa ys and alarms shoul d be determined by performing a human factors analysis 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.

CALLAWAY - SP18.2-60Rev. OL-21 5/15(d)Other alarms duri ng emergency and need for prioritization of alarms. ATTACHMENT1, DESIGN AND QUALIFICATION CRITERIA FOR PRESSURIZED WATER REACTOR INCORE THERMOCOUPLES(1)Thermocouples located at the core exit fo r each core quadrant, in conjunction with core inlet temperature data, shall be of sufficient number to provide indication of radial distribution of the coolant enthalpy (temperature) rise across representative regions of the core. Power distribution symmetry should be consi dered when determining the specific number and location of thermocouples to be provided for diagnosis of local core problems. (2)There should be a primary operator display (or disp lays) having the capabilities which follow:(a)A spatially oriented core map av ailable on demand indicating the temperature or temperature difference across the core at each core exit thermocoupl e location. (b)A selective reading of core exit temperature, continuous on demand, which is consistent with parameters pertinent to operator actions in connecting with plant-s pecific inadequat e core cooling procedures. For example, the action requirement and the displayed temperature might be either the hi ghest of all operable t hermocouples or the average of five highest thermocouples. (c)Direct readout and hard-copy cap ability should be available for all thermocouple temperatures. T he range should ex tend from 200°F (or less) to 1800°F (or more). (d)Trend capability showing t he temperature-ti me history of representative core ex it temperature values should be available on demand. (e)Appropriate alarm capability s hould be provided co nsistent with operator procedure requirements.(f)The operator-display device in terface shall be human-factor designed to provide rapid acce ss to requested displays. (3)A backup display (or displays) shoul d be provided with the capability for selective reading of a minimum of 16 operable thermocouples, 4 from each core quadrant, all within a time in terval no greater th an 6 minutes. The range should extend from 200°F (or less) to 2300°F (or more).

CALLAWAY - SP18.2-61Rev. OL-21 5/15(4)The types and locations of displa ys and alarms shoul d be determined by performing a human-factors analysis 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. (5)The instrumentation must be evalua ted for conformance to AppendixB (to NUREG-0737), "Design and Q ualification Criteria fo r Accident Monitoring Instrumentation," as modi fied by the provisions of items 6 through 9 which follow. (6)The primary and backup display ch annels should be electrically independent, energized from independent station Class 1E power sources, and physically separated in accordance with Regulatory Guide 1.75 up to and including any isolati on device. The primar y display and associated hardware beyond the isolation device need not be Class 1E, but should be energized from a high-reli ability power source, battery backed, where momentary interruption is not tolerable. The backup display and associated hardware should be Class 1E. (7)The instrumentation should be environmentally qualified as described in AppendixB, Item1, except that seismic qualification is not required for the primary display and associated hardwa re beyond the isolater/ input buffer at a location accessible for ma intenance following an accident. (8)The primary and backup display cha nnels should be de signed to provide 99 percent availability for each channel with respect to functional capability to display a minimum of four thermocouples pe r core quadrant. The availability shall be addressed in Technical Specifications. (9)The quality assurance pr ovisions cited in AppendixB, item5, should be applied except for the primary disp lay and associated hardware beyond the isolation device. 18.2.13.2UnionElectricResponseItem II.F.2 of NUREG-0737 specif ies the following as required documentation concerning instrumentation for detection of inadequate core cooling (ICC):(1)A description of the pr oposed final system including:

CALLAWAY - SP18.2-62Rev. OL-21 5/15(a)A final design description of additional instrumentation and displays(b)A detailed description of existing instrumentati on system (e.g., subcooling meters and incore thermocouples), including parameter ranges and displays, which provide operating information pertinent to ICC consideration(c)A description of any planned modifications to the instrumentation systems described in it em 1.b above. (2)The necessary design analysis, including evaluation of various instruments to monitor water level, and available test data to support the design described in item1 above. (3)A description of additi onal test programs to be conducted for evaluation, qualification, and calib ration of additional instrumentation. (4)An evaluation, including proposed actions, of the conformance of the ICC instrument system to this document, including Attachment1 and AppendixB. Any deviations should be justified. (5)A description of the computer functions associat ed with ICC monitoring and functional specifications for relevant software in the process computer and other pertinent calculators. The reliability of nonredundant computers used in the system should be addressed. (6)A current schedule, incl uding contingencies, for installation, testing and calibration, and implementation of any proposed new instrumentation or informative displays. (7)Guidelines for use of the additional instrumentati on, and analyses used to develop these procedures. (8)A summary of key operat or action instructions in the current emergency procedures for ICC and a description of how these proc edures will be modified when the final monito ring system is implemented. (9)A description and schedule commitment for any additional submittals which are needed to support the acceptability of the proposed final instrumentation system and emer gency procedures for ICC.

The following is a discussion of each of the above items as t hey relate to the Callaway instrumentation fo r detection of ICC:

CALLAWAY - SP18.2-63Rev. OL-21 5/15(1)The final system to be used at Callaway to detect ICC consists of a reactor vessel level instrumentation system and a thermocouple/core cooling monitor system. ReactorVesselLevelInstrumentationSystem (RVLIS)

The design provides r edundant safety-grade (Class1E) reactor vessel water level instrumentation. The four reactor vessel water level indicators (LI-1311, LI-1312, LI-1321, and LI-1322) are locate d on the main control board reactor auxiliaries console, RL-021. The RVLIS (Figure18.2-13) utilizes two sets of two d/p cells.

These cells measure the pressure differential between the bottom of the reactor ve ssel and the top of the vessel. This d/p measuring system utilizes cells of differing ranges to cover different flow behavior with and without pump operat ion as discussed below:(a)Reactor Vessel-Narrow Range (P b)This measurement provides an i ndication of reac tor vessel level from the bottom of the reactor vessel to the top of the reactor during natural circulation conditions. (b)Reactor Vessel-Wide Range (P c)This instrument provides an indica tion of reactor core and internals pressure drop for any combination of operating RCPs. Comparison of the measured pre ssure drop with the nor mal, single-phase pressure drop provides an approxim ate indication of the relative void content or density of the circ ulating fluid.

The indication of coolant density is significant only when the subcooling is near zero.

This instrument monitors coolan t conditions on a continuing basis during forced flow conditions. To provide the required accuracy fo r level measurem ent, temperature measurements of the impul se lines are provided. These measurements, together with existing reactor coolant temperature measurements and wide-range RCS pressu re, are employed to compensate the d/p transmitter outputs for differences in system density and reference leg density, particularly during the chang e in the environment inside the containment structure fo llowing an accident.

Additional information (i.e., analyse s, evaluations) concerning the Westinghouse generic reactor vessel level instrumentation system has been submitted to the NRC via Reference7. The specific hardware for Callaway is not exactly as documented in Reference 7, since the Callaway design does not include a separate measurement of reactor vessel level CALLAWAY - SP18.2-64Rev. OL-21 5/15 above the hot legs (reactor vessel upper range). However, the analyses, evaluations, and conclusions contained in Reference 7 are applicable to Callaway, since they are not sensit ive to the above-mentioned design difference. Thermocouple/CoreCoolingMonitorSystem (T/CCMS)

The T/CCMS is a core ex it thermocouple/core cooling detection system which provides presentation and display of the status of the core heat removal capability to both the plant operators and the technical support center. In the control room, the two subcooling te mperature indicators are located immediately above th e four level indicators on the vertical portion of the control board, RL-022. The core exit thermocouple display is mounted on the subcooling monitor cabinet, RP-081. The system consists of redundant channels and output trains of thermocouple measurements, wide-range hot- and cold-leg RTD temperatures, and reactor pressure signals. These parameters are used by the system to display thermocouple temperatures and to ca lculate saturation temperatures and margin of saturation (Tsat margin), which is often referred to as subcooling.

The calculations are performed by the system which is based on microprocessor and data handling devices. ThermocoupleMonitor The core exit thermocouple portion of the ICC system is arranged as follows:(a)Primary system The primary system meas ures all the thermoco uples via isolators located in the qualifi ed backup system cabinet. (b)Backup systemThe backup system consists of tw o channels, each monitoring half of the 50 core outle t thermocouples. The system has separa tion and redundancy as well as qualification to comply with AppendixB of NUREG-0737 (see th e discussion of item (4) below). CoreCoolingMonitor The core cooling monitor portion of ICC system compar es core outlet thermocouple temperatures and hot- and cold-leg RTD temperatures with the saturation temperature based on the lo west of three pres sure signals.

CALLAWAY - SP18.2-65Rev. OL-21 5/15This system has separation and redundan cy as well as qualification to comply with AppendixB of NUREG-0737 (see the di scussion of item (4) below). One of the indicators of an approach to an ICC situation is the response of the core exit thermocouples (T/Cs) to the presence of superheated steam.

The core exit thermocoupl es do not provide an indi cation of the amount of core voiding. Response of the core exit T/Cs provides a direct indication of the existence of ICC, the effectiv eness of ICC recovery actions, and restoration of adequate co re cooling. The co re is adequately cooled whenever the vessel mixt ure level is above the t op of the core, and the core may have a significant void fraction and still be adequately cooled.

The thermocouple/core cooling moni tor combines the functions of monitoring for excessiv e core exit thermoc ouple temperatures and monitoring both core exit thermocouple temperatures and hot- and cold-leg RTD temperatures for saturation margin (Tsat meter). The system consists of two redundant channels, each monitoring half of the core outlet thermocoup les, and four hot- and cold-leg RTDs. Three reactor pressure input signals are us ed with the au ctioneered low pressure used by the microprocessor to perform the Tsat margin function. The thermocouple temperatures are co rrected for reference junction temperature with three reference j unction temperature signals input to each channel. (All of t he thermocouples connect ed to one c hannel are from one referenc e junction unit.)

The system's two redundant trains utilize the following safety-grade equipment:(a)Thermocouples(b)Reference junction boxes (c)RTDs(d)Termination board assemblies(e)Microprocessor assemblies (f)Remote displays (g)Analog meters(h)Recorders CALLAWAY - SP18.2-66Rev. OL-21 5/15(i)Power supplies(j)Connections and cabling The equipment listed above and shown in Figure 18.2-12 has been designed to satisfy the requirements of IEEE St andard 279. This safety-grade system is isolated from the non-Class 1E plant computer, technical support center, and data links by qualified isolation devices. Details of is olation device qual ification were provided in SLNRC 84-100, dated June 29, 1984 and SLNRC 84-104, dated Ju ly 26, 1984.

The system can display individual thermocoupl e temperatures and provides two levels of alarm when preset temperatures are exceeded. The display is an alphanumeric panel digital display with 8 lines of 32 characters each located at the processing cabinets, behind the main c ontrol board.

The thermocouple moni tor can calculate and display core outlet temperature quadrant tilts based on thermo couple temperatures. The tilts calculated by each unit are based on half the total number of core thermocouples. This info rmation is also available to the operator at the main control board via the plant computer.

The core cooling monitor comp ares core outle t thermocouple temperatures and hot- and cold-leg RTD temperatures with the saturation temperature based on the lowest of three pressure signals. Two levels of alarm are provided for the core cooling (Tsat) monitor function. The margin to saturati on is displayed on two redundant analog meters on the vertical section of the main control board and are visible to an operator at the control console.

The thermocouple/core cooling moni tor provides info rmation to the operator that assists in the per formance of the required manual safety functions following a ConditionII, III, or IV event. This includes information relative to maintaining the plant in a safe shutdown condition or to proceeding to a cold shutdown condition consistent with the Technical Specification limits. At Callaway, the core exit T/Cs prot rude slightly from the bottom of the upper core plate support columns. In this location, they measure the temperature of the fluid leaving the core region through the flow passages in the upper core plate.

Flow from the upper head must enter the upper plenum via the control ro d drive guide tube s before being able to enter the upper core plate flow passages.

In addition, th e LOCA blowdown depressurization behavior must be such that there is a flow reversal for the CALLAWAY - SP18.2-67Rev. OL-21 5/15core exit T/Cs to detect the upper head fluid temperature. The upper head fluid is expected to mix with the upper plenum fluid as it drains from the upper head.

The potential for core exit T/C cooling from colder upper head fluid, while the core has an appreciable void fr action, is not view ed as a potential problem for the detection of an inadequate core cooling situation. Although some Semiscale tests indicated co re voiding while the upper head was liquid solid, these tests do not imply that the core exit T/Cs would give an ambiguous indication of ICC calculations for a Westinghouse PWR, and consideration of the core exit T/C design would not result in ambiguous ICC indications.

Additional information co ncerning the thermocouple

/ core cooling monitor system is provided in Table 18.2-3. (2)Reference 7 provid es a design analysis and evaluation of the instrumentation for detection of inadequate core cool ing (ICC). By letter dated February 20, 1986, (Reference 15) Westinghouse reported to the NRC the results of an evaluation relative to the consequences of larger than expected post-accident errors on the T/

CCMS. These errors, which are identified in WCAP 8587 (Reference 16), affected subcooling margin calculations, the use of T/Cs for ICC indication and the use of T/Cs as temperature compensation for RV LIS. Based on the revised error values, restrictions were placed on use of T/Cs for RVLIS and subcooling margin calculations and the EOP Guidelines were revis ed to incorporate new ICC indication setpoints and revised accuracy requirements were developed for RVLIS. Modifications to plant hardware and procedures, required by the larger than expected T/CCMS errors, have been implemented at Callaway.(3)Additional testing of the equipment described above has been completed in order to establish and upgr ade qualification of the equipment to comply with NUREG-0737.

The test programs were:(a)Qualification tests of core exit thermocouples(b)Qualification tests of reference (temperature compensation) junction boxes(c)Qualification tests of electroni cs to add to the system computer and technical support center is olators and microprocessors CALLAWAY - SP18.2-68Rev. OL-21 5/15(d)Qualification of isol ation devices, cables and connectors, reference leg RTDs and hydraulic isolators.(4)An evaluation of th e conformance of the reactor vessel level instrumentation system to NUREG-0737 is provided in Reference7.

An evaluation of the conformance of the thermocouple/ core cooling monitor system to NUREG-0737 (Attachment1 and AppendixB) is as follows:(a)Attachment1, Item (1)

The core exit thermocouples have been qualified so as to comply with the recommendations of Regulatory Guides 1.89 and 1.100, as clarified hereinafter. The thermocouples are located at the core exit and in an arrangement such t hat each of the redundant microprocessor systems has core exit temperatures distributed over the entire core, in sufficient number to deter mine the radial power distribution and so located as to verify power distribution symmetry among core quadrants. (b)Attachment 1, Item (2)

The primary operator display is a computer-based display and calculation system. It provides information as required by subitems (a) through (f) of Attach ment 1, Item (2), in Section 18.2.13.1. (c)Attachment1, Item (3)The backup system to display thermocouple readings is located in a cabinet which also houses the core cooling monitor. Backup system display is accomplished by the Class 1E ICC instrumentation including the microprocessor asse mblies, remote displays, analog meters, and recorders. This system has a 40-character (alphanumeric) display line locat ed on the front of each of the microprocessor drawers.

This backup system ca n display all of the 50 individual ther mocouple temperatures wi thin 6 minutes. The range extends from 0°F to 2500°F. (d)Attachment 1, Item (4)

Human factors consider ation of the types and locations of displays and alarms is discussed in Sections 18.1.16 and 18.3.2. The ICC instrumentation has been consider ed in the overal l human factors evaluation.

CALLAWAY - SP18.2-69Rev. OL-21 5/15(e)Attachment 1, Item (5)Conformance to the specific items of Appendix B to NUREG-0737 is as follows:1)Appendix B, Item (1)

The thermocouple/core cooling monitor instrumentation has been tested to establish environmental qualification in accordance with Regulatory Gu ide 1.89 (NUREG-0588).

This qualification requirement applies to the complete instrumentation channel from t hermocouple to display where display indicates the remote display, analog meter, and recorder. Qualified channel is olation devices isolate this qualified instrumentation from the data links, technical support center display, and plant computer display. The seismic portion of the environmental qualification testing has been performed to comply with Regulatory Guide 1.100.

This seismic qualification pr ovides assurance that the instrumentation will continue to read within the required accuracy following, but not necessarily during, a safe shutdown earthquake. Instrumentation whose ranges are required to extend beyond those ranges calculated in th e most severe design basis accident event for a given variable have been qualified using the following criteria.

The qualification environment is based on the design basis accident events, except the assumed maximum of the value of the monitored va riable is the value equal to the maximum range for the variable. The monitored variable is assumed to approach this peak by extrapolating the most severe initial ramp associated with the design basis accident events. The decay for this variable is considered proportional to the decay for this variable associated wi th the design basis accident events. No additional qualification margin needs to be added to the extended range variable. All environmental envelopes except that pertaining to t he variable measured by the information display channel ar e those associated with the design basis accident events. The above environmental qualific ation requirement does not account for steady-state elevated levels that may occur in other environmental parame ters associated with the CALLAWAY - SP18.2-70Rev. OL-21 5/15extended range variables. For example, a sensor measuring containment pressure must be qualified for the measured process variable range, but the corresponding ambient temperature is not mechanistical ly linked to that pressure. Rather, the ambient temperature value is the bounding value for design basis accident events analyzed in Chapter 15.0. The extended range requirement ensures that the equipment will continue to provide in formation should conditions degrade beyond those pos tulated in the safety analysis.

Since variable ranges are nonm echanistically determined, extension of associated parameter levels is not justifiable and has, therefore, no t been required. 2)Appendix B, Item (2)

The purpose for qualifying the th ermocouple/ core cooling monitoring system is to generate evidence that the equipment will maintain and perform its functions during a design basis event. It is of special concern during the qualification effort to uncov er common mode failures.

The single-failure criteria fo r the computer and information beyond the isolator does not apply to this data-based information device as re ferred to in NUREG-0737 (clarification item (8)). In relation to diversification, the use of reactor vessel level instrumentat ion adds diversification to the ICC instrumentation. Inclusion of the core cooling (Tsat margin) monitoring function s enhances even further the capability of the Callaway ICC instrumentation. 3)Appendix B, Item (3)The instrumentation is ener gized from Class 1E power sources. 4)Appendix B, Item (4)Although not specifically recommended by NUREG-0737, the ICC instrumentation complies wi th the applicable portions of IEEE Standard 279. The systems utilize two tr ains; therefore, the "Exemption" as defined in Paragraph 4.11 of IEEE Standard 279 is app licable here. 5)Appendix B, Item (5)

CALLAWAY - SP18.2-71Rev. OL-21 5/15 The ICC equipment falls under the quality assurance requirements applicable to Class 1E equipment. Refer to Appendix 3A for a discussion of the quality assurance regulatory guides. 6)Appendix B, Item (6)A digital (40-character) line display is provided for the thermocouple readings in the backup system. The computer-based (primary) ther mocouple indication system has continuous (recording) displays. 7)Appendix B, Item (7)

The backup Class 1E system (w hich is on demand) includes redundant recorders. The co mputer-based (primary) indication system has continuous (recording) displays. 8)Appendix B, Item (8)The instruments are specifical ly identified on the control panels so that the operator can easily discern that they are intended for use under a ccident conditions. 9)Appendix B, Item (9)The Callaway ICC instrumentat ion complies with isolation requirements.10)Appendix B, Item (10The Callaway ICC instrumentation is testable as required.11)Appendix B, Item (11)

Servicing, testing, and calibrat ing programs are specified to maintain the capability of the monitoring instrumentation. 12)Appendix B, Item (12)The access to the thermocouple/core cooling monitor permits removing channels for service (l ocation is a main control room). The testing and/or maintenance is facilitated by this system location.13)Appendix B, Item (13)

CALLAWAY - SP18.2-72Rev. OL-21 5/15The design facilitates administra tive control of the access to all setpoint adjustments, module calibration adjustments, and test points.14)Appendix B, Item (14)The monitoring instrumentat ion design minimizes the development of conditions that would cause meters, annunciators, recorders, alarms , etc., to give anomalous indications potentially confusing to the operator. 15)Appendix B, Item (15)The instrumentation is designed to facilitate t he recognition, location, replacement, repair, or adjustment of malfunctioning components or modules. 16)Appendix B, Item (16)The instrumentation used in both the reacto r vessel level instrumentation system and thermocouple monitoring receives input signals directly from the sensors that measure the parameters. The core coo ling monitor also derives most of the signals directly from the sensors except in the case where Tsat pressures and others are obtained from the protection set. 17)Appendix B, Item (17)The instruments used for ICC instrumentation are also used, with the exception of the reactor vessel le vel indication, for monitoring normal operation of the plant to the extent that it is practical. No loss of sensitivit y is expected due to this use. 18)Appendix B, Item (18)

Periodic testing is in accordanc e with the app licable portions of Regulatory Guide 1.118. (f)Attachment 1, Item (6)The instrumentation system power supplies are in conformance with this requirement. However, the required circuits to the thermocouples are separated only to the maximum extent possible. (g)Attachment 1, Item (7)

CALLAWAY - SP18.2-73Rev. OL-21 5/15The instrumentation qualification is discussed in item (4).e.1 above.(h)Attachment 1, Item (8)The instrumentation system is in conformance with this requirement.(i)Attachment 1, Item (9)

Quality assurance is discuss ed in item (4).e.5 above. (5)The nonredundant plant computer displays the thermocouple and Tsat functions for the primary display. These functions are performed by the Class 1E ICC instrumentation. The Class 1E microprocessor performs the calculations and provides the signal s to both the primary and Class 1E backup display. (6)In general, the system electronics are verified, maintained, and calibrated on-line by placing one of the redundant trains into a test and calibrate mode while leaving the othe r train in operation to monitor inadequate core cooling.A general verification was performed befo re shipment, but plant specific data was not used. The capability exists for the operator to verify the operation of the s ystem. This involves disc onnecting the sensors at the RVLIS electronics, providing an artificial input, and observing the response of the system on the front panel and remote display.The "7300" RVLIS incorporates circ uit cards that provide an output proportional to the change in resistance of the RTD. The card contains a resistance bridge driven by a power supply to produce a signal proportional to the changes in resistance of the RTD, and a si gnal characterizer which accommodates linear calibration of non-linear RTDs.

On-line calibration of the system is made possibl e by the "card edge" adjustments. The circuit ca rds were calibrated at the factory; however, if the function is changed or a component on the card is replaced, the calibration procedure is given wi thin the equipment reference manual.(7)and (8) The Westinghou se Owners Group has deve loped ICC operating guidelines. These guide lines were developed using the generic ICC analyses discussed in Section 18.1.8. These generic guidelines were considered, as a ppropriate, by Callaway in developing plant specific operating procedures. (9)No additional submittals are requir ed, with the exc eption of emergency operating procedures.

CALLAWAY - SP18.2-74Rev. OL-21 5/1518.2.13.3ConclusionThe Callaway instrumentation for detection of ICC meets the int ent of guidance in NUREG-0737, Item II.F.2.18.2.14EMERGENCY POWER FOR PRESSURIZER EQUIPMENT (II.G.1)18.2.14.1NRCGuidancePerNUREG-0737 Position Consistent with satisfying the requirements for General Design Criteria10, 14, 15, 17, and 20 of AppendixA to 10CFR Part50 for the event of loss-of-offsite power, the following positions sh all be implemented:

Power Supply for Pressurizer Relief and Block Valves and Pr essurizer Level Indicators (1)Motive and control components of the power-operated relief valves (PORVs) shall be capable of being supplied from either the offsite power source or the emergen cy power source when the offsite power is not available. (2)Motive and control components associated with the PORV block valves shall be capable of being supplied from either the offsite power source or the emergency power source when the offsite powe r is not available. (3)Motive and control pow er connections to the emergency buses for the PORVs and their associat ed block valves shall be through devices that have been qualified in accordance with safety-grade requirements. (4)The pressurizer level indication instrument channels shall be powered from the vital instrument buses. The buses shall have the capa bility of being supplied from either the offsite po wer source or the emergency power source when offsite pow er is not available.Clarification (1)Although the primary c oncern resulting from le ssons learned from the accident at TMI is that the PORV block valves must be closable, the design should retain, to the extent practical, the capability to also open these valves. (2)The motive and control power for the block-valve should be supplied from an emergency power bus different from the source supplying the PORV.

CALLAWAY - SP18.2-75Rev. OL-21 5/15(3)Any changeover of the PORV and block-valve motive and control power from the normal offsite power to the emergency onsite power is to be accomplished manually in the control room. (4)For those designs in which instrument air is needed for oper ation, the electrical power supply should be required to have the capability to be manually connected to the emergency power sources. 18.2.14.2UnionElectricResponse The pressurizer level indica tion channels are powered from vital, Class 1E buses and displayed in the control room.

These buses are described in Section 8.3; they are capable of being supplied from onsite emergency power (diesel generators) or offsite power. The pressurizer PORVs and bl ock valves are powered from vital, Class 1E power sources. The separation group assignment is indicated on system drawings in FSAR Section 5.1

.The pressurizer PORVs are relied on to perform the following safety functions: a.Pressure control during a shutdown concurrent with loss of offsite power; b.Overpressure protecti on at low reactor coolant system pressures; andc.RCS depressuriza tion in the mitigation of the accidents discussed in Sections 15.5.1 and 15.6.3.These functions are described in Sections 5.2 and 5.4 (A). The PORV block valve is provided to isolate the PORV should the PORV develop an unacceptable leakage during operation.

The pressurizer level indicati on is used during normal oper ation to control pressurizer level (see Figure 7.2-1, sheet 11).

The pressurizer level indicati on is used for the reactor tr ip logic and is a displayed parameter for safe shutdown control. The sa fety design basis of the pressurizer level indication is provided in Section 7.2 and Section7.5. 18.2.14.3Conclusion The Callaway design for t he emergency power for pressurizer equipment satisfies ItemII.G.1 of NUREG-0737.

The Callaway design proposes an alternative to the power supply assignment proposed for the pressurizer PORVs and PORV block valves. The alternative is justified based on the diversity in power supply assignments for these CALLAWAY - SP18.2-76Rev. OL-21 5/15 valves, i.e., motor-operated (AC) block valves and solenoid-operated (DC) PORVs and based on the above requirements for PORV use.18.2.15REQUESTS BY NRC INSPECTI ON AND ENFORCEMENT BULLETINS(II.K.1)

Position

"(C.1.5) - Review all valve positions, positioning requirements, positive controls, and related tests and maintenanc e procedures to ensure proper ESF functioning. See Bulletins79-06A Item 8,79-06B Item 7, and 79-08 Item 6 in Reference 11 (NUREG-0560).""(C.1.10) - Review and modify, as required, procedur es for removing safety-related systems from service (and restoring to service) to ensure that operability status is known.

See Bulletins79-05A Item 10 ,79-06A Item 10,79-06B Item 9, and 79-08 Item 8 in Reference 11 (NUREG-0560).""(C.1.17) - For Westinghouse-designed reactors, trip the pre ssurizer low-level coincident signal bistables, so that safety injecti on would be initiated wh en the pressurizer low-pressure setpoint is reached regardless of the pressurizer level. See Bulletin 79-06A and Revision 1, Item 3 in Reference 11 (NUREG-0560).18.2.15.2Union Electric Response The development and review of procedures for testing, maintenance and system operation for the SNUPPS facilities were carried out as a joint effort between Union Electric, Wolf Creek Nuclea r Operating Corporation, and other consultants. This development and review effort has considered the concerns of Items C.1.5 and C.1.10 of NUREG-0694 and Union El ectric has performed the acti ons required by the applicable I&E Bulletin sections.The item related to the safety injection logic is not applicable to the Callaway design (See Figure 7.2-1, Sheet8).18.2.15.3Conclusion Union Electric has developed and reviewed pl ant procedures in accordance with the NRC guidance in II.K

.1 of NUREG-0694.

CALLAWAY - SP18.2-77Rev. OL-21 5/1518.2.16ORDERS ON FACILITIES WITH BABCOCK & WILCOX NUCLEAR STEAM SUPPLIER SYSTEMS (II.K.2)18.2.16.1ControlofAuxiliaryFeedwaterIndependentof theInt egrated Control System (II.K.2.2)Not applicable to We stinghouse pressurized water reactors. 18.2.16.2AuxiliaryFeedwaterSystemUpgrading(II.K.2.8)Not applicable to We stinghouse pressurized water reactors. 18.2.16.3FailureModeEffectsAnalysisontheIntegrated ControlSystem(II.K.2.9)Not applicable to We stinghouse pressurized water reactors. 18.2.16.4Safety-GradeAnticipatoryReactorTrip(II.K.2.10)Not applicable to We stinghouse pressurized water reactors. 18.2.16.5ThermalMechanicalReport--EffectofHigh-Pres- sureInjectiononVessel Integrity forSmall-BreakLoss-of-CoolantAccidentwithnoAux iliary Feedwater(II.K.2.13)18.2.16.5.1NRCGuidancePerNUREG-0737 PositionA detailed analysis shall be per formed of the thermal-mech anical conditions in the reactor vessel during recovery from small breaks with an extended loss of all feedwater. Clarification

The position deals with the potential for thermal shock of reactor vessels resulting from cold safety injection flow. One aspect that bears heavily on the effects of safety injection flow is the mixing of safety injection wate r with reactor coolant in the reactor vessel.

B&W provided a report on July30,1980 that discussed the mixing question and the basis for a conservative analysis of the potential for thermal shock to the reactor vessel. Other PWR vendors are also required to address this issue with regard to recovery from small breaks with an extended loss of all feedwater. In particular, demonstration shall be provided that sufficient mixing would occur of the cold high-pressure in jection (HPI) water with reactor coolant so that significant thermal shock effects to t he vessel are precluded.

CALLAWAY - SP18.2-78Rev. OL-21 5/1518.2.16.5.2Union Electric ResponseWestinghouse (in support of the Westinghouse Owners Group) has developed a method and has performed analyses for a spectrum of small loss-of-coolant accidents. The method employs the NOTRUMP co mputer program to generate the thermal/ hydraulic transients. The thermal transients on the reactor vessel bel tline and the inlet nozzle are analyzed based on the thermal/hydraulic data from the NO TRUMP code. The Westinghouse developed pressuri zed thermal shock evaluation (PTS) methodology has been submitted to and approved by the NRC (Reference13). The Callaway calculated RTNDT values are well below the scr eening criterion of 10 CFR 50.61.(See ULNRC-1244, dat ed January 21, 1986; NRC letter dated December 15, 1986; ULNRC-1675, dated November 10, 1987 and ULNRC-1867, dated November 30, 1988.)18.2.16.6EffectsofSlugFlowonSteamGeneratorTubes (II.K.2.15)Not applicable to We stinghouse pressurized water reactors. 18.2.16.7ReactorCoolantPumpSealDamage(II.K.2.16)Not applicable to We stinghouse pressurized water reactors. 18.2.16.8PotentialforVoidingintheReactorCoolant System During Transients (II.K.2.17)18.2.16.8.1NRC Guidance Per NUREG-0737 Position Analyze the potential for voidi ng in the reactor coolant system (RCS) during anticipated transients. ClarificationThe background for this concern and a request for this analysis was originally sent to the Babcock and Wilcox (B&W) licensees in a letter from R.W.Reid , NRC, to all B&W operating plants, dated January9,1980. 18.2.16.8.2Union Electric ResponseWestinghouse (in support of the Westinghouse Owners Gr oup) has performed a study which addresses the potential for void formation in Westinghouse-designed nuclear steam supply systems during natur al circulation cooldown/depressurization transients.

This study has been submitted to the NRC by the Westinghouse Owners Group (Ref.1) and is applicable to the Callaway Plant.

CALLAWAY - SP18.2-79Rev. OL-21 5/15In addition, the Westinghouse Owners Group has developed appropriat e modifications to the Westinghouse Owners Group Emergency Response Guidelines (ERGs) to take the results of the study into account so as to precl ude void formation in the upper head region during natural circulation cooldown/depressurization transients, and to specify those conditions under which upper head voiding may occur. The SNUPPS utilities have considered the generic guidance developed by the West inghouse Owners Gr oup in the development of plant specif ic operating procedures. 18.2.16.9SequentialAuxiliaryFeedwaterFlowAnalysis (II.K.2.19)Not applicable to We stinghouse pressurized water reactors. 18.2.16.10Small-BreakLoss-of-CoolantAccidentWhich Repressurizes the Reactor Coolant Systemtothe Power-OperatedReliefValveSetPoint(II.K.2.20)Not applicable to We stinghouse pressurized water reactors. 18.2.17RECOMMENDATIONS FROM THE BULLETINS AND ORDERS TASK FORCE(II.K.3)18.2.17.1InstallationandTestingofAutomaticPower-OperatedReliefValve Isolation System (II.K.3.1)18.2.17.1.1NRC Guidance Per NUREG-0737 Position All PWR licensees should prov ide a system that uses the PORV block valve to protect against a small-break loss-of-coolant accident. This system will automatically cause the block valve to close when th e reactor coolant system pressure decays after the PORV has opened. Justification should be provided to ensure that fa ilure of this system would not decrease overall safety by aggravating plant transients and accidents.

Each licensee shall perform a confirmatory test of the automatic block valve closure system following installation. ClarificationImplementation of this action item was modified in the May1980 version of NUREG-0660. The change delays implementation of this action item until after the studies specified in TMI Acti on Plan item II.K.3.2 have been co mpleted, if such studies confirm that the subject system is necessary.

CALLAWAY - SP18.2-80Rev. OL-21 5/1518.2.17.1.2Union Electric ResponseWestinghouse, as a part of the response prepared for the Westinghouse Owners Group to address item II.K.3.2 (refer to Section 18.2.17.2

), has evaluated the necessity of incorporating an automatic pressurizer power-operated relief valv e isolation system. This evaluation is documented in Reference2 and concluded that such a system should not be required. The Callaway design includes the capability to remote-manually isolate the power-operated relief valves by closing block valves from the main control room.18.2.17.1.3Conclusion Based on the above discussion, Callaway meets the intent of the guidelines of NUREG-0737, Item II.K.3.1.18.2.17.2ReportonOverallSafetyEffectofPower-Operated Relief Valve Isolation System(II.K.3.2)18.2.17.2.1NRC Guidance Per NUREG-0737 Position(1)The licensee should submit a report for staff review documenting the various actions taken to decrease the probability of a small-break loss-of-coolant accident (L OCA) caused by a st uck-open, power-operated relief valve (PORV) and show how those actions constitute sufficient improvements in reactor safety. (2)Safety-valve failure rates based on past history of the operating plants designed by the specific nuclear steam supply system (NSSS) vendor should be included in the report submitted in resp onse to (1) above. ClarificationBased on its review of feedwater transients and small LOCAs for operating plants, the Bulletins and Orders Task Force in the Office of Nuclear Reactor Regulation recommended that a report be prepared and submitted for staff review which documents the various actions that have been taken to reduce the probability of a small-break LOCA caused by a stuck-open PORV and show how these actions constitute sufficient improvements in reactor safety. Action Item II.K.3.2 of NUREG-0660, published in May1980, changed the implementat ion of this recommendation as follows: In addition to modifications already implemented on PORVs, the report specified above should include safety examination of an automatic PORV isolation system identified in Task Action Plan item II.K.3.1. Modifications to reduce the likelihood of a stuck-open PORV will be considered sufficient improvements in reactor safety if they reduce t he probability of a small-break LOCA CALLAWAY - SP18.2-81Rev. OL-21 5/15caused by a stuck-open PORV such that it is not a significant contributor to the probability of a small-break LOCA due to al l causes. (According to WASH-1400, the median probability of a small-break LOCA S 2 with a break diameter between 0.5 inches and 2.0inches is 10

-3 per reactor-year with a variation rang ing from 10

-2 to 10-4 per reactor-year.)

The above-specified report should also include an analysis of safety-valve failures based on the operating experience of the pressurized-water-reac tor (PWR) vendor designs.

The licensee has the option of preparing and submitting either a plant-specific or a generic report. If a generic r eport is submitted, each li censee should document the applicability of the generic report to his own plant.

Based on the above guidance and clarification, each licensee should perform an analysis of the probability of a small-break LOCA caused by a stuck-open PORV or safety valve.

This analysis should consider modifications which have been made since the TMI-2 accident to improve the probability. This analysis shall evaluate the effect of an automatic PORV isolation system specified in Task Action Plan, Item II.K.3.1. In evaluating the automatic PORV isolation system, the potential of causing a subsequent stuck-open safety valve and the overall effect on safety (e.g., effect on other accidents) should be examined. Actual operational data may be used in this analysis, wher e appropriate. The bases for any assumptions used should be clearly stated and justified. The results of the probability analysis shoul d then be used to de termine whether the modifications already implemented have reduc ed the probability of a small-break LOCA due to a stuck-open PORV or safety valve a sufficient amount to satisfy the criterion stated above, or whether the automatic PORV isolation system specified in Task Action item II.K.3.1 is necessary. In addition to the analysis described above, the licensee should compile operational data regarding pressurizer safety valves for PWR vendor designs. These data should then be used to determine safety-v alve failure rates. The analyses should be documented in a report. If this requirement is implemented on a generic basis, each licensee should review the appropriate generic report and document its applicability to his own plant(s). The report and the documentat ion of applicability (where appropriate) should be submitted for NRC staff review by the specified date. 18.2.17.2.2Union Electric Response As mentioned in item II.K.3.1 above (Section18.2.17.1), the Westinghouse Owners Group has submitted a Westinghouse-prepared report (Ref.2) which provides a probabilistic analysis to determine the probability of a PORV LOCA, estimates the effect of the post-TMI modifi cations, evaluates an automatic PORV isolation concept and concludes that an automatic isolation capability is not required and provides PORV and CALLAWAY - SP18.2-82Rev. OL-21 5/15 safety valve operational data for Westinghouse plants.

Because of the sensitivity analyses included in the report , the report is generic and is applicable to Callaway. The report identifies a significant reduction in the PORV LOCA probability as a result of post-TMI modifications, and the calculations compare favorably with the operational data for Westinghouse plants (included as an a ppendix to the report). 18.2.17.2.3Conclusion The requirements of this item were resolved by submittal of the analysis report discussed in Reference 2.18.2.17.3ReportingSafetyandReliefValveFailuresand Challenges(II.K.3.3)18.2.17.3.1NRC Guidance Per NUREG-0694 Assure that any failure of a PORV or safety valve to close will be reported to the NRC promptly. All challenges to the PORVs or safety valves should be documented in the annual report. 18.2.17.3.2Union Electric ResponseThe failure of a PORV to close on demand and a failure of a primary system safety valve to close will no lo nger be reported per G eneric Letter 97-02. 18.2.17.3.3Conclusion Union Electric's commitm ent documented above meets the requirements of NUREG-0737, II.K.3.3.18.2.17.4AutomaticTripofReactorCoolantPumpsDuring Loss-of-Coolant Accident (II.K.3.5)18.2.17.4.1NRC Guidance Per NUREG-0737 PositionTripping of the reactor coolant pumps in case of a loss-of-coolant accident (LOCA) is not an ideal solution. Licensees s hould consider other solutions to the smal l-break LOCA problem (for example, an increase in the safety injection fl ow rate). In the meantime, until a better solution is found, the reactor coolant pumps s hould be tripped automatically in case of a small-break LOCA. The signals designated to initiate the pump trip are discussed in NUREG-0623. Clarification CALLAWAY - SP18.2-83Rev. OL-21 5/15 This action item has been revised in the May1980 version of NUR EG-0660 to provide for continued study of cr iteria for early reacto r coolant pump trip. Implementation, if any is required, will be delayed accordingly. As part of the continued study, all holders of approved emergency core co oling (ECC) model s have been required to analyze the forthcoming LOFT test (L3-6). The capability of the industr y models to correctly predict the experimental behavior of this test will have a strong input on the staff's determination of when and how the reactor coolant pumps sh ould be tripped. 18.2.17.4.2Union Electric Response

In response to IE Bulletin No.79-06C, Westinghouse (in support of the Westinghouse Owners Group) performed an analysis of delayed reactor coolant pump (RCP) trip during small-break LOCAs. This analysis is documented in Reference3 and is the basis for the Westinghouse and SNUP PS position on RC P trip (i.e., automa tic RCP trip is not necessary since sufficient time is ava ilable for manual trippi ng of the RCPs). Westinghouse (again in support of the Westinghouse Owners Group) has performed test predictions of the LOFT Ex periment L3-6. The result s of these predictions are documented in References4 and 5. The results constitute both a best estimate model prediction with the NOTRUM P computer program and an evaluation model prediction with the WFLASH computer program, using the suppl ied set of in itial boundary assumptions.

By letter dated February 8, 1983, the NRC issued Generic Letter 83-10c. The NRC concluded that each nuclear plant applicant should determine the need to trip the reactor coolant pumps following an accident or transi ent. By SNUPPS lett ers dated April 22, 1983 and April 13, 1984, (SLNRC 83-21 and SLNRC 84-66) responses to Generic Letter 83-10c were provided. The responses referenced previous Westinghouse Owner's Group reports dated December 1, 1983 and March 9, 1984.

The NRC has issued G eneric Letter 85-12 which confirmed the acceptab ility of the information provided by the Westinghouse Owner's Group, in response to Generic Letter 83-10, and requested that plant-specific information be subm itted to the NRC. By letter dated November 27, 1 985 (ULNRC-1215), UE responded to Generic Letter 85-12. By letter dated August 4, 1988, the NRC staff found that Un ion Electric addressed the Generic Letter 85-12 criteria, that the material submitted was accept able, and that the requirements in regard to TMI Acti on Item II.K.3.5 were satisfied.18.2.17.5EvaluationofPORVOpeningProbabilityDuring Overpressure Transient (II.K.3.7)Not applicable to We stinghouse pressurized water reactors.

CALLAWAY - SP18.2-84Rev. OL-21 5/1518.2.17.6ProportionalIntegralDerivativeController Modification(II.K.3.9)18.2.17.6.1NRC Guidance Per NUREG-0737 PositionThe Westinghouse-recommended modification to the proportional integral derivative (PID) controller should be implemented by affected licensees. ClarificationThe Westinghouse-recommended m odification is to raise the interlock bistable trip setting to preclude derivativ e action from opening the pow er-operated relief valve (PORV). Some plants have proposed changing the derivati ve action setting to zero, thereby eliminating it from consideration.

Either modification is acceptable to the staff. This represents a newly available option. 18.2.17.6.2Union Electric Response

The Callaway design originally included a pressu re integral derivative (PID) controller in the power-operated relief valve control circuit. The time derivative const ant in the PID controller for the pressurizer PORV was turned to "OFF" prior to commercial operation. The appropriate plant pr ocedure for calibrating the set points in this system reflected this decision.

Setting the derivative time constant to "OFF," in effec t, removed the der ivative action from the controller. Removal of the derivative action decreased the likelihood of opening the pressurizer PORV since the actuation signal for the valve was then no longer sensitive to the rate of change of pressurizer pressure. Th is PID controller was used in the actuation circuitry for BB-PCV-0455A. A subse quent plant modifica tion revised the PORV actuation circuitry such that the PID controller is no longer used in the actuation circuitry for BB-PCV-0455A. The current design is reflected in Figures 7.7-4 , 7.2-1 (sheets 6 and 11), and 7.6-4 (sheets 1 and 2)..18.2.17.6.3Conclusion The NUREG-0737 provis ions for the PID controller no longer apply to Callaway.18.2.17.7ProposedAnticipatoryTripModification(II.K.3.10)18.2.17.7.1NRC Guidance Per NUREG-0737 PositionThe anticipatory trip modification proposed by some licensees to confine the range of use to high-power levels should not be made until it has b een shown on a plant-by-plant CALLAWAY - SP18.2-85Rev. OL-21 5/15basis that the probability of a small-break loss-of-coolant accident (LOCA) resulting from a stuck-open power-operated relief valve (PORV) is substantially unaffected by the modification. Clarification This evaluation is requir ed for only those licensees/applicants who propose the modification. 18.2.17.7.2Union Electric ResponseThis anticipatory trip modification is included in t he SNUPPS design.

The NRC has raised t he question of whether the pre ssurizer power-operated relief valves would be actuated for a turbine trip without reactor trip below a power level of 50percent (P-9 set point). An analysis has been perfo rmed using realistic yet conservative values for the core physics parameters (p rimarily reactivity feedback coefficients and control rod wo rths), and a conservatively high initial power, average reactor temperature (TAVG), and pressurizer pressure le vel to account for instrument inaccuracies.

The transient was initiated from the set point for the P-9 interlock, namely 50percent of the reactor full power level plus 2percent for power measurement uncertainty. This is a conservative starting point, and would bracket all transients initiated from a lower power level. The core physics parameters used were the ones that would result in the most positive reactivity f eedbacks (i.e., highest power levels).

The steam dump valves were assumed to be actuated by the load rejection controller. Based upon the results from t he analysis, the peak pressure reached in the pressurizer would be 2,302 psia. The set point for the actuat ion of the pressurizer power-operated relief valves is 2,350 psia. Even including the +/-20psi pressure measurement uncertainty, there is still a margin of 28ps i between the peak pre ssure reached and the minimum activation pressure for the pre ssurizer power-operated relief valves.

An additional analysis has been per formed to determine the c onsequences (specifically the likelihood of the pressurizer power-operated relief valves opening) of having a turbine trip due to a loss of condenser vacuum. The major difference between this analysi s and the one presented above is that now the normal steam dump system is un available, and the steam relief must be carried out through the atmospheric relief valves. Since there is a longer delay time before the atmospheric reliefs reach their set point (in comparison to the normal steam dump system) and their capacity is about one-half of the steam dump system, there is an increased likelihood that the pressurizer PORVs will open.

CALLAWAY - SP18.2-86Rev. OL-21 5/15Figure18.2-14 shows the plant operati ng ranges for which the pressurizer PORVs will open for a turbine trip due to a loss of condenser signal. Above 50percent power, a turbine trip will cause a reactor trip (due to P-9 set point), and the pressurizer PORV set point will not be reached. Belo w a power level of 35 to 40 percent (depending on fuel burnup), the pressurizer spray rate is adequate to maintain the pressurizer pressure below the set point. Ther efore, only in the narrow band between about 35 and 50percent power will the pressurizer PORVs open for a loss of condenser.

Based upon the operating history of current plants, the c hances of getting a condenser unavailable signal (and hence a turbine trip) is about 156 out of 10 7 operating hours. Assuming 98percent plant avail ability and a 40-year plant lifetime, this works out to about four condenser unavailable turbine trips occurring during the normal life of a plant.

Assuming an equal chance of having the plant operate anywh ere between 0 and 100percent power (an unr ealistic value, since they usually operate either at a full or no load level), the chances of having a condenser unavailable signal generate a transient which would result in the opening of the pressurizer PORVs is less than one per plant lifetime. 18.2.17.7.3Conclusion The analysis described above demonstrates an acceptably low probability of a small LOCA caused by a stuck open PORV.18.2.17.8JustificationuseofCertainPORVs(II.K.3.11)18.2.17.8.1NRC Guidance Per NUREG-0694 PositionDemonstrate that the PORV installed in the pl ant has a failure rate equivalent to or less than the valves for wh ich there is an operating history. 18.2.17.8.2Union Electric ResponseThe PORVs to be used in the Callaway design are pilot-op erated relief valves. These valves are a new design and were supplied by Crosby. The va lve design was tested in the Electric Power Research In stitute (EPRI) valve test pr ogram (refer to NUREG-0737, Item II.D.1 for more information). Th e performance of the Crosby PORVs was comparable to other designs tested. In addition, the analysis of PORVs in accordance with NUREG-0737, Item III.K.3.2 (Section 18.2.17.2) addresses valve failure rates.18.2.17.8.3Conclusion Based on the EPRI testing and PORV analysis ident ified above, failur e rates for the Callaway PORV design are adequately addressed.

CALLAWAY - SP18.2-87Rev. OL-21 5/1518.2.17.9ConfirmExistenceofAnticipatoryReactorTrip Upon Turbine Trip (II.K.3.12)18.2.17.9.1NRC Guidance Per NUREG-0737 Position Licensees with Westinghouse-designed operating plants should confirm that their plants have an anticipatory reactor trip upon turbine trip. The licen see of any plant where this trip is not present should provide a concept ual design and evaluation for the installation of this trip. 18.2.17.9.2Union Electric Response The Callaway design includes an anticipatory reactor trip upon turbine trip (refer to Figure7.2-1

). 18.2.17.10Separation of High-Pressure Coolant Injection and Reactor Core Isolation Cooling System Initiation Levels--Analysis and Implementation II.K.3.13)Not applicable to We stinghouse pressurized water reactors. 18.2.17.11IsolationofIsolationCondensersonHigh Radiation(II.K.3.14)Not applicable to We stinghouse pressurized water reactors. 18.2.17.12Modify Break-Detection Logic to Prevent Spurious Isolation of High-Pressure Coolant Injection and Reactor Core Isolation Cooling (II.K.3.15)Not applicable to We stinghouse pressurized water reactors. 18.2.17.13Reduction of Chall enges and Failures of Relief Valves--Feasibility Study and System Modification (II.K.3.16)Not applicable to We stinghouse pressurized water reactors. 18.2.17.14Report on Outages of Emergency Core-Coolin g Systems Licensee Report and Proposed Technical Specific ation Changes (II.K.3.17)18.2.17.14.1NRC Guidance Per NUREG-0737 PositionSeveral components of the emergency core-c ooling (ECC) systems are permitted by technical specifications to have substantial outage times (e.g., 72hours for one CALLAWAY - SP18.2-88Rev. OL-21 5/15diesel-generator; 14days for th e HPCI system). In addition, there are no cumulative outage time limitations for E CC systems. Licensees should submit a report detailing outage dates and lengths of outages for all ECC systems for the last 5years of operation. The report should al so include the causes of the outages (i.e., controller failure, spurious isolation). Clarification

The present technical specifications contain limits on allowable outage times for ECC systems and components. However, there are no cumulative outage time limitations on these same systems. It is po ssible that ECC equi pment could meet present technical specification requirements but have a high unavailability because of frequent outages within the allowable tec hnical specifications. The licensees should submit a report detailing outage dates and length of outages for all ECC systems for the last 5year s of operation, including causes of the outages. This report will provide the staff with a quantification of historical unreliability due to test and maintenance outages, which will be used to determine if a need exists for cumulative outage requirements in the technical specifications.

Based on the above guidance and clarification, a detailed repo rt should be submitted. The report should contain (1) outage dates and duration of outages; (2) cause of the outage; (3) ECC systems or components involved in the outage

and (4) corrective action taken. Test and maintenance outages should be included in the above listings which are to cover the last 5years of operation. The licensee should propose changes to improve the availability of ECC equipment, if needed.

Applicant for an operating license shall establish a plan to meet these requirements. 18.2.17.14.2Union Electric Response

Union Electric will provide safety system outage in formation as required by regulations and the Callaway Technical Specifications.

In addition, records are retained of the ma intenance, inspections, and surveillance tests of the principal items related to nuclear safety. These records can be reviewed by the NRC for additional specific data on component availability. The documentation will include: 1)outage dates and duration, 2)cause of the outage, 3)systems or components involved in the outage, and 4)corrective action taken. 18.2.17.14.3Conclusion

By letter dated May 9, 1989, NRC removed the requ irement for a five year report of ECCS outages. Union Electric reports safety system outages as required by 10 CFR 50.72, 10 CFR 50.73, the Technical Specifications and other applicable regulations. This CALLAWAY - SP18.2-89Rev. OL-21 5/15 reporting ensures that the dat a requested by Item II.K.3.17 of NUREG-0737 is available to NRC.18.2.17.15Modification of Au tomatic Depressurization S ystem Logic--Feasibility for Increased Diversity for Some Event Sequences (II.K.3.18)Not applicable to We stinghouse pressurized water reactors. 18.2.17.16InterlockonRecirculationPumpLoops(II.K.3.19)Not applicable to We stinghouse pressurized water reactors. 18.2.17.17Restart of Core Spray and Low-Pressure Coolant-Injection Systems (II.K.3.21)Not applicable to We stinghouse pressurized water reactors. 18.2.17.18Automatic Switc hover of Reactor Core Is olation Cooling System Suction--Verify Procedures and Modify Design (II.K.3.22)Not applicable to We stinghouse pressurized water reactors. 18.2.17.19Confirm Adequacy of Space Cooling for High- Pressure Coolant Injection and Reactor Core Isolation Cooling Systems (II.K.3.24)Not applicable to We stinghouse pressurized water reactors. 18.2.17.20Effect of Loss of Alternating-Current Power on Pump Seals (II.K.3.25)18.2.17.20.1NRC Guidance Per NUREG-0737 PositionThe licensees should determine, on a plant-specific basis, by analysis or experiment, the consequences of a loss of cooli ng water to the reactor recirc ulation pump seal coolers.

The pump seals should be designed to withstand a complete lo ss of alternating-current (ac) power for at least 2hou rs. Adequacy of the seal design should be demonstrated. Clarification

The intent of this po sition is to prevent e xcessive loss of reacto r coolant system (RCS) inventory following an anticipated operational occurrence. Loss of ac power for this case is construed to be loss of offsite power. If seal failure is the consequence of loss of cooling water to the reactor co olant pump (RCP) seal coolers for 2hours, due to loss of offsite power, one acceptable solution woul d be to supply emergency power to the CALLAWAY - SP18.2-90Rev. OL-21 5/15component cooling water pump. This topic is addressed for Babcock and Wilcox (B&W) reactors in Section II.K.2.16. 18.2.17.20.2Union Electric Response

During normal operation, seal injection flow from the c hemical and volume control system is provided to cool the RCP seals, and the co mponent cooling water system provides flow to the therma l barrier heat exchanger to li mit the heat transfer from the reactor coolant to the RCP internals. In the event of a loss of offsite power, the RCP motor is deenergized and both of these cooling supplies are terminated; however, the diesel generators are automatically started and both seal injection flow and component cooling water to the therma l barrier heat exchanger are automatically restored within seconds. Either of these cooling supplies is adequate to provide seal cooling and prevent seal failure due to a loss of seal cooling during a loss of offsite power for at least 2hours. 18.2.17.20.3Conclusion The Callaway design meets the RCP seal cooling requirements of this section.18.2.17.21Provide Common Reference Level for Vessel Level Instrumentation (II.K.3.27)Not applicable to We stinghouse pressurized water reactors. 18.2.17.22Verify Qualification of Accumulators on Automatic Depressurization System Valves (II.K.3.28)Not applicable to We stinghouse pressurized water reactors. 18.2.17.23Study to Demonstrate Performance of Isolation Condensers with Noncondensibles (II.K.3.29)Not applicable to We stinghouse pressurized water reactors. 18.2.17.24Revised Small-Break Loss-of-Coolant Accident Methods to Show Compliance with 10 CFR Part 50, Appendix K (II.K.3.30)18.2.17.24.1NRC Guidance Per NUREG-0737 Position The analysis methods used by nuclear steam supply system (NSSS) vendors and/or fuel suppliers for small-break lo ss-of-coolant accident (LOCA) analysis for compliance with AppendixK to 10CFRPart50 should be revi sed, documented, and submitted for NRC CALLAWAY - SP18.2-91Rev. OL-21 5/15 approval. The revisions should account for comparisons with experimental data, including data from the LOFT Test and Semiscale Test facilities. Clarification

As a result of the accident at TMI-2, the Bulletins and Orders Task Force was formed within the Office of Nuclear Reactor Regulation. This task fo rce was charged, in part, to review the analyt ical predictions of feedwater transients and sm all-break LOCAs for the purpose of assuring the contin ued safe operation of all operat ing reactors, including a determination of acceptability of emergency guidelines for operators. As a result of the task force reviews, a number of concerns were identified regarding the adequacy of certain features of small-break LOCA models, particularly the need to confirm specific model feat ures (e.g., condensation hea t transfer rates) against applicable experimental data.

These concerns, as they applied to each lightwater reactor (LWR) vendor's models, were documented in the task force reports for each LWR vendor. In addition to the model ing concerns identified, the task force also concluded that, in light of the TMI-2 accident, additional systems ve rification of the small-break LOCA model as required by II.4 of AppendixK to 10CFR50 was needed. This included providing predictions of Semiscale Test S-07-10B and LOFT Test (L3-1) and providing experimental verification of the various modes of single-phase and two-phase natural circulation predicted to occu r in each vendor's reactor dur ing small-break LOCAs. Based on the cumulative staff requirements for additional small-break LOCA model verification, including both integral system and separate effects verification, the staff considered model revision as the appropriate method for reflec ting any potential upgrading of the analysis methods.

The purpose of the verificati on was to provide the nece ssary assurance that the small-break LOCA models were acceptable to calculate the behavior and consequences of small primary system breaks. The staff believes that this assurance can alternatively be provided, as appropriate, by additional justification of the acceptability of present small-break LOCA models with regard to specific staff concerns and recent test data.

Such justification could supplement or supersede the need for model revision. The specific staff concerns regarding small-break LOCA models are provided in the analysis sections of the B&O Task Force reports for each LWR vendor, (NUREG-0635, -0565, -0626, -0611, and

-0623). These concerns should be reviewed in total by each holder of an approved emergen cy core cooling system (ECC S) model and addressed in the evaluation as appropriate. The recent tests include the entire Semiscale small-break test series and LOFT Tests (L3-1) and (L3-2). The staff believes that the present small-brea k LOCA models can be both qualitatively and quantitatively assessed against these tests. Other separate effects tests (e.g., ORNL core uncovery tests) and future tests, as appropriate, should also be factored into this assessment.

CALLAWAY - SP18.2-92Rev. OL-21 5/15 Based on the preceding information, a detailed outline of the proposed program to address this issue should be submitted. In particular, this submittal should identify (1)which areas of the models, if any, the licensee intends to upgrade, (2)which areas the licensee intends to address by further justification of acceptability, (3)test data to be used as part of the overall verification/upgrade effort, and (4)the estimated schedule for performing the necessary work and submitting this information for staff review and approval. 18.2.17.24.2Union Electric Response The present Westinghouse Small Break Evaluation Model used to analyze the Callaway Plant (refer to Section15.6.5) is in conformance with 10CFRPart50, AppendixK. However (as documented in Ref.6), Westi nghouse has addressed the specific NRC items contained in NUREG-0611 in a model (NOTRUMP) documented in WCAP10054 (dated 12/28/82) and WCAP 10079 (dated 11/12/82). The NRC approved NOTRUMP as satisfying II.K.3.30 in a sa fety evaluation dated May 21, 1985. NOTRUMP was also found to be in full compliance with 10 CFR 50, Appendix K and was designated as the new Westinghouse licensing tool for small-break LOCA evaluations to satisfy the provisions of II.K.3.31.18.2.17.24.3Conclusion

The NOTRUMP code satisfies the prov isions of NUREG-0737 Item II.K.3.30.18.2.17.25Plant-Specific Calculations to Show Compliance With 10 CFR Part 50.46 (II.K.3.31)18.2.17.25.1NRC Guidance Per NUREG-0737 Position Plant-specific calculations using NRC-approved models for small-break loss-of-coolant accidents (LOCAs), as described in item II.K.3.30 to s how compliance with 10CFR50.46, should be submitted for NRC approval by all licensees. 18.2.17.25.2Union Electric Response The present Westinghouse Small Break Ev aluation Model and small break LOCA analyses for Callaway Plant (refer to Section15.6.5) are in conformance with 10CFRPart50, AppendixK and 10CFRPart50.46. As stated in the response to ItemII.K.3.30 (refer to Section 18.2.17.24.2), Westinghouse has a ddressed the specific NRC items contained in NUREG-0611 in a model change documented in WCAP 10054 (dated 12/28/82) and WCAP 10079 (dated 11/12/82). On May21, 1 985, the NRC approved the new Westinghouse small break LOCA model, NOTRUMP, for use in satisfying the TMI Action ItemII.K.3.30. On November 15, 1985, Union Electric informed the NRC (Reference14) that a revised Callaway LOCA analysi s was being submitted as CALLAWAY - SP18.2-93Rev. OL-21 5/15part of the Cycle Two Licensing Submittal. The revise d analysis would utilize the NOTRUMP code. The use of this code sa tisfied the requirements of TMI Action ItemII.K.3.31.

By letter dated October 16, 1986 (Referenc e 17), the NRC conclu ded that the generic study results could be used to re solve NUREG-0737, Item II.K.3.31.18.2.17.25.3Conclusion Based on the above discussion, the requirements of NUREG

-0737, Item II.K.3.31 are met.18.2.17.26Evaluation of Anticipated Transients with Single Failure to Verify No Fuel Failure (II.K.3.44)Not applicable to We stinghouse pressurized water reactors. 18.2.17.27Evaluation of Depressurization with Other than Automa tic Depressurization System (II.K.3.45)Not applicable to We stinghouse pressurized water reactors. 18.2.17.28Identify Water Sour ces Prior to Actuation of Automatic Depressurization System (II.K.3.57)Not applicable to We stinghouse pressurized water reactors. 18.2.18REFERENCES1.Letter OG-57, dated April20, 1981, Jurgensen,R.W. (Chairman, Westinghouse Owners Group) to Check, P.S. (NRC). 2.Wood, D.C.and Gottshall, C.L., "Probabilistic Analysis and Operational Data in Response to NUREG-0737 Item II.K.3.2 for Westinghouse NSSS Plants," WCAP-9804, February 1981. 3."Analysis of Delayed Reactor Coolant Pump Trip During Smal l Loss of Coolant Accidents for Westinghouse Nuclear Steam Supply S ystems," WCAP-9584 (Proprietary) and WCAP-9585 (Non-Proprietary), August1979. 4.Letter OG-49, dated March 3, 1981, Jurgensen, R.W. (Chairman, Westinghouse Owners Group) to Ross, D.F.,Jr. (NRC). 5.Letter OG-50, dated March23, 1981, Jurgensen,R.W. (Chairman, Westinghouse Owners Group) to Ross, D.F.,Jr. (NRC).

CALLAWAY - SP18.2-94Rev. OL-21 5/156.Letter NS-TMA-2318, dated September26, 1980, Anderson, T.M. (Westinghouse) to Eisenhut, D.G. (NRC). 7.Letter NS-TMA-2357, dated December 23, 1980, T. M. Anderson (Westinghouse) to D. G. Eisenhut (NRC).8.Rockwell, T., ReactorShieldingDesignManual, D. Van Nostrand Co., New York, New York, 1956.9.QAD-CG: ACombinatorialGeometryVersionofQAD-P5A, Bechtel Power Corporation internal computer code. 10.Letter SLNRC 83-0048, dated September 1, 1983, N. A.

Petrick (SNUPPS) to H.

R. Denton (NRC).11.Letter SLNRC 84-004, dated January 16, 1984, N.A.Petr ick (SNUPPS) to H.R.Denton (NRC).12.Letter SLNRC 83-002 (dis tributed as82-002), dated January7, 1983, N.A. Petrick (SNUPPS) to H.R.Denton (NRC).13."A Generic Assessment of Significant Flaw Extension, Including, Stagnant Loop Conditions, from Pressurized Thermal Shock of Reactor Vessels on Westinghouse Power Plants," WCAP 10319, December 1983.14.Letter ULNRC-1207, dated November15, 1985, R.J.Schukai (UE) to H.R.Denton (NRC).15.Letter NS-NRC-86-3099, dated February 20, 1986, Rahe, E.P. (Westinghouse) to Taylor, J. M. (NRC).16."Methodology for Qualifying Westinghouse WRD-Suppli ed NSSS Safety-Related Electrical Equipment," WCAP-8587, Rev. 6-A, dated November 1983. 17.Safety Evaluation Report, WCAP-11145, Westinghouse Small-Break LOCA ECCS Evaluation Model Generic Study with NOTRUM P Code, transmitted by NRC letter (C. Rossi) to Westinghouse Owners Group (L. Butterfield), dated October6, 1986.

CALLAWAY - SP Rev. OL-13 5/03TABLE 18.2-2 ESSENTIAL/NONESSENTIAL CONTAINMENT PENETRATIONSFig.6.2.4-1

,SheetPenetration Service Essential/

Nonessential1P-1Main steam/PORVNonessential

/essential2P-2Main steam/PORVNonessential

/essential3P-3Main steam/PORV & AFW steamNonessential

/essential4P-4Main steam/PORV & AFW steamNonessential

/essential5P-5Main/aux. feedwaterNonessential

/essential6P-6Main/aux. feedwaterNonessential

/essential7P-7Main/aux. feedwaterNonessential

/essential8P-8Main/aux. feedwaterNonessential

/essential9P-9SG blowdownNonessential10P-10SG blowdownNonessential11P-11SG blowdownNonessential12P-12SG blowdownNonessential 13P-13Containment recirculation sump suction to containment spray pump Essential14P-14Containment recirculation sump suction to RHR pump Essential15P-15Containment recirculation sump suction to RHR pump Essential16P-16Containment recirculation sump suction to containment spray pump Essential17P-21RHR hot leg injectionEssential CALLAWAY - SPTABLE 18.2-2 (Sheet 2)

Rev. OL-13 5/0318P-22RCP-B seal water supplyEssential19P-23CVCS letdownNonessential20P-24RCP seal water returnNonessential 21P-25Reactor makeup water supplyNonessential 22P-26Reactor coolant drain tank dischargeNonessential23P-27RHR cold leg injection loops 3 and 4Essential24P-28ESW supply to containment air coolers Essential25P-29ESW return from containment air coolers Essential26P-30Instrument air supplyNonessential27P-32Containment sump pump dischargeNonessential 28P-34Containment ILRT test lineNonessential 29P-36Maintenance SpareNonessential 30P-39RCP-C seal water supplyEssential 31P-40RCP-D seal water supplyEssential 32P-41RCP-A seal water supplyEssential 33P-43Auxiliary steam supply - decontaminationNonessential34P-44Reactor coolant drain tank ventNonessential35P-45Accumulator nitrogen supplyNonessential 36P-48SI pump-B, discharge to hot legs1 and 4 Essential37P-49SI pumps to cold legs 1, 2, 3, and 4 Essential38P-50Maintenance SpareNonessentialFig.6.2.4-1

,SheetPenetration Service Essential/

Nonessential CALLAWAY - SPTABLE 18.2-2 (Sheet 3)

Rev. OL-13 5/0339P-51ILRT pressure sensing linesNonessential40P-52RHR shutdown suctionEssential41P-53Fuel pool cooling and cleanup, refueling pool supply Nonessential42P-54Fuel pool cooling and cleanup, refueling pool suctionNonessential43P-55Fuel pool cooling and cleanup, refueling pool ski mmer suctionNonessential44P-56Post-LOCA hydrogen analyzer return Essential45P-57Nuclear Sampling SystemNonessential46P-58Accumulator fill line from SI pump Nonessential47P-59RVLIS Sample LineNonessential 48P-62Pressurizer relief tank nitrogen supplyNonessential49P-63Service air supplyNonessential50P-64Nuclear SamplingNonessential 51P-65Hydrogen purgeNonessential 52P-66Containment spray supply pumpBEssential 53P-67Fire protection supplyNonessential 54P-68Maintenance SpareNonessential 55P-69Pressurizer vapor sampleNonessential 56P-71ESW supply to containment air coolers Essential57P-73ESW return from containment air coolers Essential58P-74CCW supplyEssentialFig.6.2.4-1

,SheetPenetration Service Essential/

Nonessential CALLAWAY - SPTABLE 18.2-2 (Sheet 4)

Rev. OL-13 5/0359P-75CCW returnEssential60P-76CCW return RCP thermal barrierEssential61P-78S.G. drainNonessential 62P-79RHR shutdown suctionEssential 63P-80CVCS chargingNonessential 64P-82RHR discharge to hot legs loops1 and 2 Essential65P-83S.G. D sampleNonessential66P-84S.G. A sampleNonessential 67P-85S.G. B sampleNonessential 68P-86S.G. C sampleNonessential 69P-87SI pump A discharge to hot legs loops 2 and 3 Essential70P-88Boron injection supply to cold legs loops1, 2, 3, and 4 Essential71P-89Containment spray supply pumpAEssential72P-91RVLIS SampleNonessential 73P-92ECCS test line returnNonessential 74P-93R.C. loop and pressurizer liquid samples Nonessential75P-95Accumulator tank sampleNonessential76P-97Post-LOCA hydrogen analyzer return Essential77P-98Breathing AirNonessential78P-99Post-LOCA hydrogen analyzer supply EssentialFig.6.2.4-1

,SheetPenetration Service Essential/

Nonessential CALLAWAY - SPTABLE 18.2-2 (Sheet 5)

Rev. OL-13 5/0379P-101Post-LOCA hydrogen analyzer supply Essential80/81P-103/104Containme nt pressure sensing monitors Essential82P-160Containment purge exhaustNonessential 83P-161Containment purge supplyNonessential 84E-256Containment pressure transmittersEssentialFig.6.2.4-1

,SheetPenetration Service Essential/

Nonessential CALLAWAY - SP Rev. OL-17 4/09TABLE 18.2-3 DETAILS FOR THE THERMOCOUPLE/CORE COOLING MONITOR SYSTEMDisplayInformation Displayed (T-Tsat, Tsat, Press, etc.)

P-Psat subcooled-T-Tsat - superheatedDisplay Type (analog, digital, display)Analog (control board), digital (electronics package), Display (Plant Computer)Continuous or on DemandConti nuous (control board) and on demand (electronics package)

Single or Redundant DisplayRedundantLocation of DisplayCont rol board and control room Alarms (include set points)Caution:25F subcooled for RTD 15 F subcooled for T/CAlarm:0F subcooled for RTD and T/COverall uncertainty (F, psi)Digital:4 F for T/C, 3F for RTDAnalog:5 F for T/C, 5F for RTD Range of DisplayCalibrated:200 F subcooled to 2000 F superheatOverall:Never off scaleQualifications (seismic, environmental, IEEE 323)Seismic and environmental CalculatorType (process computer, dedicated digital or analog calc.)Dedicated digital If process computer is used specify availability (percent of time)

NA Single or redundant calculatorsRedundantSelection Logic (highest T., lowest press)Auctioneered high hot leg RTD or average incore thermocouple.

Auctioneered low reactor coolant pressure CALLAWAY - SPTABLE 18.2-3 (Sheet 2)

Rev. OL-17 4/09Qualifications (seismic, environmental, IEEE 323)Seismic and environmentalCalculational Technical (steam tables, functional fit, ranges)

Functional fit - ambien t to critical point InputTemperature (RTDs or T/Cs)RTDs, T/Cs, and TrefTemperature (number of sensors and locationsRTDs - 2 hot leg a nd 2 cold leg/channel T/Cs - 25 per channel Range of temperature sensorsRTDs 700 F T/Cs 2500 F Calibration unit

range 2500 FUncertainty* of temperature sensors (F at 1)See WCAP 8587Qualifications (seismic, environmental, IEEE 323)Seismic and environmental Pressure (specify instrument used)Qualified Pressure Transmitter Pressure (number of sensors and locations) 1 wide range - RCS loop 2 narrow range - pressurizer Range of pressure sensorsWide range 0-3000 psignarrow range - 1700-2500 psigUncertainty* of pressure sensors (psi at 1)See WCAP 8587Qualifications (seismic, environmental, IEEE 323)Seismic and environmental*Uncertainties must address conditions of forced flow and natural circulation.

CALLAWAY - SP18.3-1Rev. OL-21 5/1518.3EMERGENCYPREPARATIONSANDRADIATIONPROTECTION18.3.1UPGRADEEMERGENCYPREPAREDNESS(III.A.1.1)18.3.1.1NRCGuidancePerNUREG-0694 Position"Provide an emergency response plan in substantial compliance with NUREG-0654, "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," except that only a description of and completion schedule for the mean s for providing pr ompt notification to the population (App. 3), the staffing for emergencies in addition to that already required (Table B.1), and an upgraded meteorological pr ogram (App. 2) need be prov ided. NRC will give substantial weight to FEMA (Federal Emergency Management Agency) findings on offsite plans in judging t he adequacy against NUREG-0654. Perf orm an emergency response exercise to test the integrated capability and a major portion of the basic elements existing within emergency prepar edness plans and organizations. This requirement shall be met before i ssuance of a full-power license."18.3.1.2UnionElectricResponse The Callaway Plant Radiol ogical Emergency Response Plan (RERP) was submitted as Appendix 13.3A to the Callaway Plant FSAR Site Addendum but is now maintained as a separate licensing document as referenc ed in Appendix 13.3A of the FSAR. A successful emergency response exercise to test the integrated capability and major portions of the basic elements existing within the emergency preparedness plans and organizations was performed in March 1984.

Radiological Emergency Response Exercises are held in accordance with the RERP.18.3.1.3Conclusion Union Electric has provided the NRC with documentation relative to the emergency planning activities at Callaway which satisfies the requirements of 10CFR50, Section 50.47 and Appendix E, and the supplementary NRC guidanc e in NUREG-0654.18.3.2UPGRADEEMERGENCYSUPPORTFACILITIES(III.A.1.2) 18.3.2.1NRCGuidancePerNUREG-0578andNUREG-0694 (A)ONSITE TECHNICAL SUPPORT CENT ER (NUREG-0578, Item 2.2.2.b)

Position"Each operating nuclear power plant shall maintain an onsite technical support center (TSC) separate from and in close proximity to the control room that has the capability to CALLAWAY - SP18.3-2Rev. OL-21 5/15 display and transmit plant st atus to those indi viduals who are k nowledgeable of and responsible for engineering and management support to reactor operat ions in the event of an accident. The center shall be habitable to the same degree as the control room for postulated accident conditions. The licens ee shall revise hi s emergency plans as necessary to incorporate the role and locati on of the technical support center. Records that pertain to the as-build conditions and layout of structures, systems, and components shall be readily available to personnel in the TSC." Clarification (N RC Letter dated November 9, 1979)1.By January 1, 1980, each licensee should meet items 1-7 that follow. Each licensee is encouraged to provide additi onal upgrading of the TSC (items 2-10) as soon as practical, but no later than January 1, 1981.a.Establish a TSC and provi de a complete description.b.Provide plans and procedures for engineering/management support and staffing of the TSC.c.Install dedicated communications between the TSC and the control room, near-site emergency operations center, and the NRC.d.Provide monitoring (either port able or permanent) for both direct radiation and airborne radioactive contaminants. The monitors should provide warning if the radiation levels in the support center are reaching potentially dangerou s levels. The licensee should designate action levels to define when protecti ve measures should be taken (such as using breathing apparatus and potassium iodide tablets or evacuation to the control room).e.Assimilate or ensure access to Technical Data, including the licensee's best effort to have direct display of plant parameters necessary for assessment in the TSC.f.Develop procedures for perfo rming this acci dent assessment function from the control room should the TSC become uninhabitable.

2.LocationIt is recommended that the TSC be located in close proximity to the control room to ease communicati ons and access to technical information during an emergency. The center should be located on site , i.e., within the plant security boundary. The greater the distance from the control room, the more sophisticated and complete should be the communications and availability of technical information. C onsideration should be given to CALLAWAY - SP18.3-3Rev. OL-21 5/15 providing key TSC personnel with a means for gaining access to the control room.

3.PhysicalSizeandStaffing The TSC should be large enough to house 25 persons, necessary engineering data, and informa tion displays (TV monitors , recorders, etc.). Each licensee should specify staffing levels and disciplines reporting to the TSC for emergencies of varying severity.

4.Activation The center should be activated in accordance with the "Alert" level as defined in the NRC document "Draft Emergency Ac tion Level Guidelines, NUREG-0610" dated Sept ember 1979, and curren tly out for public comment. Instrumentati on in the TSC should be capable of providing displays of vital plant parameters from the time the acci dent began (t = 0 defined as either reactor or turbine trip). The shift technical advisor should be consulted on the "Notification of Unusual Event." However, the activation of the TSC is discret ionary for that class of event.

5.InstrumentationThe instrumentation to be located in the TSC need not meet safety-grade requirments but should be qualitatively comparable (as regards accuracy and reliability) to that in the cont rol room. The TSC should have the capability to access and display plant parameters independent from actions in the control room. Careful consideration should be given to the design of the interface of the TSC instrumentation to ensure that addition of the TSC will not result in any degradation of the control room or other plant functions.

6.InstrumentationPowerSupply The power supply to the TSC instrumentation need not meet safety-grade requirements, but should be reliable and of a quality compatible with the TSC instrumentation requirements. To ensure contin uity of information at the TSC, the power suppl y provided should be continuous once the TSC is activated. Consideration should be given to avoid loss of stored data (e.g., plant computer) due to momentary loss of power or switching transients. If the power supply is prov ided from a plant safety-related power source, careful attention should be given to ensure that the capability and reliability of the safety-related pow er source is not degraded as a result of this modification.

7.TechnicalData CALLAWAY - SP18.3-4Rev. OL-21 5/15Each licensee should est ablish the technical data requirements for the TSC, keeping in mind the accident assessment function that has been established for those persons reporting to TSC, during an emergency. As a minimum, data (historical in addition to current status) should be available to permit the assessment of:a.Plant Safety System Parameters for: 1)Reactor Coolant System2)Secondary System (PWRs)3)ECCS Systems4)Feedwater and Makeup Systems 5)Containmentb.In-Plant Radiological Parameters for: 1)Reactor Coolant System2)Containment 3)Effluent Treatment4)Release Pathsc.Offsite Radiological1)Meteorology2)Offsite Radiation Levels 8.DataTransmission In addition to providing a data transmission li nk between the TSC and the control room, each licens ee should review current technology as regards transmission of those parameters identified for TSC display. Although there is not a requirem ent at the present ti me, each licensee should investigate the capability to transmit plant data offsite to the emergency operations center, the NRC, the reactor vendor, etc.

9.StructuralIntegritya.The TSC need not be designed to seismic Category I requirements.

The center should be well built in accordance with sound engineering practice with due consideration to the effects of natural phenomena that may o ccur at the site.b.Since the center need not be designed to the same stringent requirements as the control room, each licensee should prepare a backup plan for responding to an em ergency from the control room.

CALLAWAY - SP18.3-5Rev. OL-21 5/15 10.Habitability The licensee should provide protection for the Technica l Support Center personnel from radiological hazards, including direct r adiation and airborne contaminants, as per General De sign Criterion 19 and SRP 6.4.a.Licensee should ensure that personnel inside the Technical Support Center (TSC) will not re ceive doses in excess of those specified in GDC-19 and SRP 6.4 (i.e., 5 rem whole-body and 30 rem to the thyroid for the duration of the accident). Majo r sources of radiation should be considered.b.Permanent monitoring systems sh ould be provided to continuously indicate radiation dose rate s and airborne radioactivity concentrations inside the TSC. The moni toring systems should include local alarms to warn per sonnel of adverse conditions.

Procedures must be provided which will specify appropriate protective actions to be taken in the event that hi gh dose rates or airborne radioactive concentrations exist.c.Permanent ventilation systems which include particulate and charcoal filters should be prov ided. The ventilation systems need not be qualified as ESF systems. The design and testing guidance of Regulatory Guide 1.52 should be followed, exce pt that the systems do not have to be redundant, seismic, instrumented in the control room, or automatically acti vated. In addition, the HEPA filters need not be tested as specified in Regulatory Guide 1.52, and the HEPAs do not have to meet the QA requirements of Appendix B to 10 CFR 50. However, spare parts should be readily available and procedures in place for replacing failed components during an accident. The systems should be designed to operate from the emergency power supply.d.Dose reduction measures such as breathing apparatus and potassium iodide tablets cannot be used as a design basis for the TSC in lieu of ventilation systems with charcoal filters. However, potassium iodide and breathing appa ratus should be available."(B)ONSITE OPERATIONAL SUPPORT CE NTER (NUREG-0578, Item 2.2.2.c)

Position "An area to be designated as the onsite Operational Support Center shall be established. It shall be separa te from the control room and shall be the place to which the operations support personnel will report in an emergen cy situation. Comm unications with the control room shall be provi ded. The emergency plan shal l be revised to reflect the CALLAWAY - SP18.3-6Rev. OL-21 5/15existence of the center and to establish the methods and lines of communication and management."(C)NEAR-SITE EMERGENCY OPERATION FACILITY (NUREG-0694)

Position "Designate a near-site Emergen cy Operations Facility (EOF) with communications with the plant to provide evaluation of radiation releases and coordination of all onsite and offsite activities during an accident.

Provide shielding against dire ct radiation, ventilation isolation capability, dedicated communications with the onsite Technical Support Center , and direct display of radiological and meteorological parameters."18.3.2.2UnionElectricResponse The emergency response faci lities for the Callaway Plant follow the guidance of NUREG-0696, Final Report, entitled "Func tional Criteria for Emergency Response Facilities", to the extent described in the following portions of Section 18.3.2.2. Standard engineering practices were us ed for the design, manufacturing, and c onstruction of these facilities and equipment, as descri bed in SLNRC 81-38, dated June 1, 1981.

NRC Generic Letter 82-33, dated December 17, 1982 prov ided guidance for meeting regulatory requirements for, among other issues, NUREG-0737, Item III.A.1.2. Based on the NRC review of t he response to Generic Letter 82-33 (SLNRC 83-19, da ted April 15, 1983), a license condition (License Condition C(7)(b)) was issued which required that the TSC and EOF be operational prior to startup following the first refueling outage at Callaway Plant. This license condition was closed out by ULNRC-1288, dated April 8, 1986.TechnicalSupportCenterThe Technical Support Center (TSC) at the Callaway Site is located within the protected area and near the on-site buildings that contain the offi ces of managerial, engineering and the plant support personnel. The location of the Technical Support Center is shown in the RERP.This location for the TSC was selected because there is no suitable space within the power block and because:-This location facilitates acti vation of the TSC, since the personnel designated to man the TSC have their offices nearby.-There is ready accessibility to plant data available in the Serv ice Building which is not stored in the TSC (e.g., vendor manuals).

CALLAWAY - SP18.3-7Rev. OL-21 5/15The distance from the TSC to the control room is approximately 700 fe et. The walking time is estimated to be about three minutes.The TSC is a one story building located at grade level. The walls are reinforced concrete 8 inches thick and the roof is reinforced concrete 6 inches thick. The structural design is in conformance with the Unifor m Building Code. Within the TSC there is working space that contains displays of plant status, meeting and discussion areas, communications equipment, and document storage. Additional areas within the TSC are occupied by a mechanical equipment room, which contains HVAC equipment, a standby diesel-generator for the TSC, and limited toilet and kitchen. This is sufficient space for at least 25 persons, including five NRC per sonnel. For any extended duration of TSC operation, additional to ilet, locker room, and ki tchen facilities in t he Service Building are available.The HVAC system for the TSC supplies outside air appropriately c ooled or heated and has provisions to filter both inlet air and recirculat ed air if radiation le vels are high. The filter train contains HEPA and c harcoal filters. Switchover to the filtered recirculation mode is manual.

Radiation monitoring in the TSC is performed using elec tronic dosimeters. These designated electronic dosimeter s have a range of 0 to 100,000 mR/hr, and provide an alarm function based on a pr e-designated set point.

Airborne radioactivity in the TSC is monitored using a continuous air monitor. This monitor is located in an area common to TSC inhabitants. The monitor provides an indication of airborne radioactive material collected on a particulate filter. The continuous air monitor has an alarm function. A portable air sampler would be used to obtain a grab sample when the continuous air sa mpler is in alarm. Air sa mpler filter media would be analyzed to determine the level of part iculate and radioiodine concentration.

Electric power to the TSC in a post-accident situati on is normally provided by a transformer from off-site power. Alternatively, there is a standby diesel generator, rated at 288 kVA, that is start ed manually utilizin g dedicated battery power. The diesel generator has sufficient capacity to power all TSC loads, includ ing plant computer terminals, communi cations equipment, HVAC and lighting. In addition, the diesel generator has sufficient capacity to power selected loads in t he Service Building Computer Room, in the event power is lost to the Se rvice Building during normal operation or under post-accident conditions.

Essential equipment in the TSC is also provided with power supplies to keep the equipment operable during a power interruption, as for example, loss of offsite power after activation of the TSC and until the standby diesel generator is started and assumes load. Selected plant co mputer terminals and co mmunications systems have uninterruptable power supplies.

Emergency lighting consisting of self-contained battery units is also provided in the TSC.

CALLAWAY - SP18.3-8Rev. OL-21 5/15 Protective clothing, respirat ors, and personnel radiation monitors to permit up to 10 persons to function within radiat ion areas are accessible to the TSC.

The conditions for manning t he TSC are described in general terms in the Callaway Radiological Emergency Response Plan. Detailed procedures have been developed, as Emergency Plan impl ementing procedures.OperationsSupportArea The Operations Support Area (OSA) is described in t he Radiological Emergency Response Plan. The OSA provides ample space for assembly of personnel and has communications with various other emergency facilities. Equipment, tools and protective clothing are also available. EmergencyOperationsFacility At Callaway the Emergency Oper ations Facility (EOF) is located approximately 1 mile from the plant, as discussed in the RERP. It is a one-s tory building of 13,000 square feet.The EOF working space is suffic ient for at least 35 persons , consisting of 25 persons designated by the licensee including state and local official s, 9 persons from the NRC and one person from FEMA. The structural design of the EOF is in conformance to the Uniform Building Code. Walls are concrete, approximately 10 inches thick and the roof consists of double-T pre-cast concrete secti ons with a minimum concrete thickness of approximately 6 inches. The st ructure provides radiation shielding equivalent to a protection factor greater than 5.The HVAC system for the EOF is similar to that of the TSC, except it contains only HEPA and no charcoal filters.

Radiation monitoring in the EOF is the same as described for the TSC.

Electric power for the EOF is normally provided by a transformer from offsite power. In addition there is a dedicated standby diesel-generator to operate the EOF in the event of loss of offsite power. The standby diesel generator is started manually, utilizing dedicated standby power. As in the TSC, Selected Plant computer terminals and communications equipment ar e provided with an Uninterruptible Power Supply.

Emergency lighting consisting of self-contained battery units is also provided in the EOF.

In the event the EOF becomes uninhabitable, a backup EOF will be est ablished in the State of Missouri Emergency Operations Center, Jefferson City, MO.Jefferson City is located approximately 25 miles southwest of the plant site.TechnicalData CALLAWAY - SP18.3-9Rev. OL-21 5/15 The Emergency Response Facility Information System (ERFIS) is an application of the Plant Computer. System displays, individual data points displays, tr ends and historical values are available for al l major plant systems. ERFI S displays and printers are available in the TSC and EOF.

The Plant computer provides ra diological and meteorological data as well as trending capabilities. Displays are located in the Control Room , TSC, Health Physics Access Area, EOF and Plant Computer Room.The Safety Parameter Display System is available to aid operators in the rapid detection of abnormal operating events.

SPDS displays are available in the Control Room, TSC, and EOF.TaskFunctionsfortheTSCandEOF Refer to Section 18.3.1.218.3.2.3Conclusion The functional description of ea ch emergency response facility described above details how Union Electric meets the appropriate NRC guidance.18.3.3IMPROVING LICENSEE EMERGENCY PREPAREDNESS - LONG TERM(III.A.2)18.3.3.1NRCGuidancePerNUREG0737"Each nuclear facility shall upgrade its emergency plans to provide reasonable assurance that adequate protective measures can and will be taken in the event of a radilogical emergency. Spec ific criteria to meet this requirement is delineated in NUREG-0654 (FEMA-REP-1), "Criteria for Preparation and Ev aluation of Radiological Emergency Response Plans and Preparedne ss in Support of Nuclear Power Plants."ClarificationIn accordance with Task Action Plan Item III.A.1.2, "Upgrade Emergency Preparedness," each nuclear power facility wa s required to immediately upgrade its emergency plans with criteria provided Oc tober 10, 1979, as revised by NUREG-0654 (FEMA-REP-1, issued for interim use and comment, Januar y 1980). New plans were submitted by January 1, 1980, using the Octo ber 10, 1979 criteria. Reviews were started on the upgraded plans using NUREG-0654. Concomitant to these actions, amendments were developed to 10 CFR Part 50 and Appendix E to 10 CFR Pa rt 50, to provide the long-term implementation requirements. These new rules we re issued in the Federal Register on August 19, 1980, with an effective date of No vember 3, 1980. The revised rules delineate requirements for emergency preparedness at nuclear reactor facilities.

CALLAWAY - SP18.3-10Rev. OL-21 5/15 NUREG-0654 (FEMA-REP-1), "Criteria for Preparation and Ev aluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," provides detailed items to be included in the upgraded emergency plans and, along with the revised rules, provides for meteorologica l criteria, means for pr oviding for a prompt notification to t he population, and the need for emergency respon se facilities see Item III.A.1.2 (of NUREG-0737 ).Implementation of the new ru les levied the requirement fo r the licensee to provide procedures implementing t he upgraded emergency plans to the NRC for review.

Publication of Revision 1 to NUREG-0654 (FEMA-R EP-1) which incorporates the many public comments received is expected in October 1980. This is the document that will be used by NRC and FEMA in their evaluation of emergency plans submitted in accordance with the new NRC rules.NUREG-0654, Revision 1., NUREG-0696, "Functional Criteria for Emergency Response Facilities," and the amendments to 10 CFR Part 50 and Appendix E to 10 CFR Part 50 regarding emergency preparedness, provide more detailed criteria for emergency plans, design, and functional crit eria for submission of upgraded emergency plans for installation of prompt notific ation systems. These revis ed criteria and rules supersede previous Commission guidance for the upgrading of emergency preparedness at nuclear power facilities.

Revision 1 to NUREG-0654, "Critria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," provides meteorological criteria to fulfill, in part, the standard that "Adequate methods, systems, and equipment for assessing and monitoring actual or potential offsite consequences of a radi ological emergency condi tion are in use" (see 10 CFR 650.47). The position in Appendix 2 to NUREG-0654 outlines four essential elements that can be categorized into three functions: measurements, asse ssment, and communications.

Proposed Revision 1 to Regulatory Guide 1.23, "Meteorological Measurements Programs in Support of Nuclear Power Plants," has been adopted to provide guidance criteria for the primary meteorological measurements program consisting of a primary system and secondary system(s) where necessary, and a backup system. Data collected from these systems are intended for use in the assessment of the offsite consequences of a radiol ogical emergency condition.

Appendix 2 to NUREG-0654 delineates two classes of assessment capabilities to provide input for the evaluation of offs ite consequences of a radiological emergency condition. Both classes of capabilities provide input to decisions regarding emergency actions. The Class A capability should provide information to determine the necessity for notification, shelteri ng, evacuation, and, during the initial phase of a radiological emergency, making confirmatory radiological measurements. The Class B capability should provide inform ation regarding the placement of supplemental meteorological monitoring equipment, and the need to make addit ional confirmatory radiological measurements. The Class B capability shall identify the areas of contaminated property CALLAWAY - SP18.3-11Rev. OL-21 5/15and food stuff requiring protective measures and may also provide information to determine the necessity fo r sheltering evacuation.

Proposed Revision 1 to Regulatory Guide 1.

23 outlines the set of meteorological measurements that should be a ccessible from a system that can be interrogated; the meteorological data s hould be presented in th e prescribed format. The results of the assessments should be accesibl e from this system; this information should incorporate human-factors engineering in its display to convey the essential inform ation to the initial decision makers and subsequent management team. An integrated system should allow the eventual incorporation of effuent monitoring and radiolog ical monitoring information with the environmental transport to provide direct dose consequence assessments.Requirements of the new emergency-preparedness rules under Paragraphs 50.47 and 50.54 and the revised Appendix E to Part 50 taken together with NUREG-0654 Revision 1 and NUREG-0696, when approved for issuance, go beyond the previous requirements for meteorological programs. To provide a realistic time frame for implementation, a staged schedule has been established with compensating actions provided for interim measures."18.3.3.2UnionElectricResponse See response to 18.3.1.2.18.3.4INTEGRITY OF SYSTEMS OUTSIDE OF CONTAINM ENT (III.D.1.1)18.3.4.1NRCGuidancePerNUREG-0737 Position 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-l ow-as-practical levels. This program shall include the following: (1)Immediate leak reduction(a)Implement all practical le ak reduction measures for all systems that could carry radioactive fluid outside of containment. (b)Measure actual leakage rates with system in operation and report them to the NRC. (2)Continuing Leak Reduction--Establish and implement a program of preventive maintenance to reduce leakage to as-low-as-practical CALLAWAY - SP18.3-12Rev. OL-21 5/15 levels. This program shall include periodic integrated leak tests at intervals not to exceed ea ch refueling cycle. Clarification Applicants shall provide a summar y description, together with initial leak-test results, of their program to reduce leakage from systems outside the containment that would or could contain primary coolant or other highly radi oactive fluids or gases during or following a serious transient or accident. (1)Systems that should be leak tested are as fo llows (any other plant system which has similar functions or postaccident characteristics, even though not specified herein , should be included):

Residual heat removal (RHR)

Containment spray recirculation High-pressure inject ion recirculationContainment and primary coolant sampling

Reactor core isolation coolingMakeup and letdown (PWRs only)Waste gas (includes headers and cover gas system outside of the containment in addition to decay or storage system)Include a list of systems containing radioactive materials which are excluded from program and provide justification fo r exclusion. (2)Testing of gaseous systems should include helium leak detection or equivalent testing methods. (3)Should consider program to reduce leakage 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 October17, 1979. 18.3.4.2UnionElectricResponse This defines Union Electric's program to re duce leakage from thos e portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to as low as practical levels. The sy stems considered include the CALLAWAY - SP18.3-13Rev. OL-21 5/15 recirculation portion of the containment spray system, safety injection system, chemical and volume control system, and RHR syst em. The program is as follows:

A description of the Union Electric program was prov ided by ULNRC-693, dated December2, 1983.18.3.4.3Conclusion The Callaway design includes provisions to insure the integrity of fluids systems which are postulated to contain highly contaminated fluids fo llowing a design bas is accident.

The provision is based on the preservice and inservice tests r equired by the ASME Code. These provisions pr ovide assurance that thes e systems will perform their 1.Preventive maintenance and periodic visual inspection requirements: PROGRAM:One aspect of the P.

M. program is the periodic replacement of valve pa ckings, pump seals, and flange gaskets based on service life. This service life is based on both maintena nce history and visual inspections. Periodic walkdowns of accessible systems are performed. One objective of these walkdowns is to identify and correct leakage both from re circulation systems and other secondary systems.

Operations, via th eir normal duties and responsibilities, also walk-down and visually inspect accessible systems. Identific ation and correction of leakage is one of the crit eria specified for these walkdowns. 2.Integrated leak test requirements for each system at refueling cycle intervals or less: PROGRAM:Callaway is committed to ASME SectionXI for commercial operation. SectionXI requires VT-2 examinations on Class2 systems during each inspection period. For Callaway, this amounts to a VT-2 visual examination for leakage on all recirculation systems every 3 to 4years.

In addition, Oper ations performs leakage testing on all recirculation systems with systems at operating pressure. This is a ccomplished per written procedure on a refueling frequency.

CALLAWAY - SP18.3-14Rev. OL-21 5/15 intended functions, including l eaktightness, following a de sign basis accident. This commitment satisfies ItemI II.D.1.1 of NUREG-0737. 18.3.5IMPROVED INPLANT IODINE INSTRUMENTATION UNDER ACCIDENT CONDITIONS18.3.5.1NRCGuidanceperNUREG-0737 Positiona.Each licensee shall provide equi pment and associ ated training and procedures for accurately determining the airborne iodine concentration in areas within the facility where pl ant personnel may be present during an accident.ClarificationEffective monitoring of increasing iodine levels in the buildings under accident conditions must include the use of portable instruments using sample media that will collect iodine selectively over xenon (e.g., silver zeolite) 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 data might be required.b.Unanticipated isolated "hot spots" may occur in locations where no stationary monitoring instrumentation is located.c.Unexpectedly high background radiation levels near stat ionary monitoring instrumentation after an accident ma y interfere with filter radiation readings.d.The time required to retrieve samples after an a ccident may result in high personnel exposures if t hese 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 auxiliary buildings will not have sufficiently 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 air free of noble gases. The licensee shall have the capabi lity to measure accurately the iodine concentrations present on t hese samples under accident co nditions. There should be sufficient samplers to sample all vital areas.

CALLAWAY - SP18.3-15Rev. OL-21 5/1518.3.5.2UnionElectricResponse Equipment and associated training and procedures are available to enable the accurate determination of airborne radi oiodine concentrations in areas within the facility where plant personnel may be present during an accident. Silver Zeolite cartridges will be used for radioiodine sampling. Typically sa mples will be anal yzed using a gamma spectroscopy system. Capabiliti es exist to remove interfer ing gaseous activity from the cartridge by purging with clean, noble gas free air or nitrogen or by plac ing the cartridge in a vacuum dessicator. Gr oss activity determination ma y be performed using a count rate meter, without purging, fo r a rapid indication of radioiodi ne concentrations. If high background precludes the use of the counting facilities on site, backup facilities are available at the University of Missouri, Research Reactor.18.3.6CONTROL ROOM HABITABILITY (III.D.3.4)18.3.6.1NRCGuidanceperNUREG-0737 PositionIn accordance with Task Action Plan ItemIII.D.3.4 and control room habitability, licensees shall ensure that c ontrol room operators will be adequately protected against the effects of accidental rele ase of toxic and radioactive gases and that the nuclear power plant can be safely operated or shut down under design basis accident conditions (Criterion19, "Control Room," of AppendixA, "General De sign Criteria for Nuclear Power Plants," to 10CFR Part50). Clarification (1)All licensees must make a submittal to the NRC regardless of whether or not they met the criteria of the referenced Standard Review Plans (SRP) sections. The new clarification specifies that licensees that meet the criteria of the SRPs should provide the basis for their conclusion that SRP6.4 requirements are met. Licensees may establish this basis by referencing past submittals to the NRC and/

or providing new or additional information to supplement past submittals. (2)All licensees with control rooms that meet the criteria of the following sections of the Standard Review Plan: shall report their findings regarding the specific SRP sections as explained below. The following documents shoul d be used for guidance: 2.2.1-2.2.2Identification of Potential Hazards in Site Vicinity, 2.2.3Evaluation of Potential Accidents, and6.4Habitability Systems CALLAWAY - SP18.3-16Rev. OL-21 5/15a.Regulatory Guide1.78, "Assumptions for Evaluating the Habitability of a Nuclear Power Plant C ontrol Room During a Postulated Hazardous Chemical Release"; b.Regulatory Guide1.95, "Protection of Nuclear Power Plant Control Room Operators Against an Accident al Chlorine Release"; and, c.K.G.Murphy and K.M.Campe, "Nuclear Power Plant Control Room Ventilation System Design for Meeting General Design Criterion19," 13th AEC Air Cleaning Conference, August1974.

Licensees shall submit the results of thei r findings as well as the basis for those findings by Janaury1, 1981. In providing the basis for the habitability finding, licensees may reference their past submittals. Licensees should, however, ensure that these submitta ls reflect the current fa cility design and that the information requested in Attachment 1, to NUREG 0737, item III.D.3.4 is provided.(3)All licensees with contro l rooms that do not meet the criteria of the above-listed references, Standard Review Plans, Regulatory Guides, and other references.

These licensees shall perform the nece ssary evaluations and identify appropriate modifications. Each licensee submittal shall include the results of the analyse s of control room concentrations from postulated accidental release of toxi c gases and control room operator radiation exposures fr om airborne radioactive mate rial and dire ct radiation resulting from design-basis accidents. The toxic gas accident analysis should be performed for all potential haz ardous chemical releases occu rring either on the site or within 5miles of the plant-site boundary. Regulatory Guide1.78 lists the chemicals most commonly encountered in the ev aluation of control room habitability but is not all inclusive. The design-basis-accident (DBA) radiation source term should be for the loss-of-coolant accident (LOCA) contai nment leakage and engineered safe ty feature (ESF) leakage contribution outside the cont ainment, as described in AppendixA and B of Standard Review Plan Chapter15.6.5. In addition, boiling-water reacto r (BWR) facilit y evaluations should add any leak age from the main steam isolation valves (MSIV) (i.e., valve-stem leakage, valve seat leakage, main steam isolation valve leakage control system release) to the containment leakage and ESF leakage following a LOCA. This should not be construed as altering the staff recommendations in SectionD of Regulatory Guide1.96 (Rev.2) regarding MSIV leak age-control systems. Other DBAs should be reviewed to determine whether they might constitute a more-severe control-room hazard than the LOCA. In addition to the accident-analysis results, which should either identify the possible need for control-room modification s or provide assurance that the habit ability systems will CALLAWAY - SP18.3-17Rev. OL-21 5/15operate under all postulated conditions to permit the control-room operators to remain in the control room to take appropriate actions required by General Design Criterion19, the licensee should submit suff icient informati on needed for an independent evaluation of the adequacy of the habitability systems. Attachment1 lists the info rmation that should be provided along with the licensee's evaluation. 18.3.6.2UnionElectricResponse The safety design bases for the habitability system for the control ro om are defined in Section6.4. This section also discusses the applicable recommendations of Regulatory Guides1.78, and 1.95. The results of dose calculations for a design basis loss-of-coolant accident re lease are presented in Section15.6.5 and 15A.3. The design of the habitability system for the control room envelope meets the appropriate recommendations of Regulatory Guide 1.78 and 1.95 and requirements of GDC 19. 18.3.6.3Conclusion The design of the control room habitability system meets the recommendations of itemIII.D.3.4 of NUREG-0737.