Text

Forwards Response to Clarification Items in NRC Re post-TMI Requirements.Encl Contains List of ECCS Outages for Past 5 Yrs & Training Program Requirements for Shift Technical Advisors
	ML18025B263
Person / Time
Site:	Browns Ferry
Issue date:	12/23/1980
From:	Mills L; TENNESSEE VALLEY AUTHORITY
To:	Harold Denton; Office of Nuclear Reactor Regulation
References
	TASK-1.A.1.1, TASK-2.K.3.27 NUDOCS 8012290237
	Download: ML18025B263 (174)
	v • d • e

REGULATORY INFORMATION-DISTRIBUTIO SYSTEM (RIDS)

ACCESSION NBR:8012290237 DOC ~ DATE: 80/12/23 NOTARIZED! YES FACIL:50 259 Br owns Ferry Nuclear Power Station~

Unit 1~

Tennessee 50 260 Br owns Ferry Nuclear Power Station~

Unit 2i Tennessee 50 296 Browns Ferry Nuclear Power Station~

Unit 3i Tennessee AUTH BYNAME AUTHOR AFFILIATION MILLS'

~ M ~ 'ennessee Valley Authority RECIP ~ NAME RECIPIENT AFFILIATION DENTONgH ~ Rs Office, of Nuclear Reactor Regulation~

Director DOCKET' 05 0500026 96 SUBJECTS Forwar ds response to clarification items in NRC 801031 l tr re post TMI requir ements.Encl contains list of ECCS outages for past 5 yrs 6 training program requirements for shift technical advisors.

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<+GLosscp6 DISTRIBUTION CODE:

A001S COPIES RECEIVED:LTR ENCL SIZE:

TITLEi General Distribution for after Issuance of Operating License NOTES:

RECIPIENT IO CODE/NAME IPPOLI TO T ~

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INTERNAL: D/DIRgHUM FAC08 I8E 06 OEL 11 G FILE 01 COPIES LTTR ENCL 13 13 1

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EXTERNAL: ACRS NSIC 09 05 16 16 1

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~~~ 80 1980 TOTAL NUMBER OF COPIES REQUIRED; LTTR 39 ENCL.

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~s i KihlNESSEE: VALLFY AUTHORlTY GHAT ANOC A. T" PINESS=

37401 400 Chestnut Street Tower XX December 23, 1980 Mr. Harold R. Denton, Dmrector Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washin'gton, DC 20555

Dear Mr. Denton:

Tn the Matter of'he

)

Tennessee Valley Authority

)

Docket Nos. 50-259 50-260 50-296 As requested in D. G. Eisenhut's October 31, 1980, letter to All Licensees of Operating Plants and Applicants f'r Operating Licensees and Holders of Construction Permits regarding post-TMl requirements, enclosed is our response for Browns Ferry Nuclear Plant which addresses the

-'mplementat'on dates for clarification items listed in Enclosure 1 to the October 31, 1980, letter.

TVA intends to be fully responsive to these requirements and we will continue to make a best-faith effort in that regard.

However, we believe that a margin of flexibility (for good cause shown) in implementing these requirements is essential for the reasons outlined in my June 23, 1980, letter to you regarding five additional TMI-2 related items.

Based on the enclosed

response, continued operation of the Browns Ferry Nuclear Plant is justified and the operating licenses for Browns Ferry units 1, 2, and 3 should not be modified, suspended or revoked.

Very truly yours, TENNESSEE VALLEY AUiHORlTY

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M. Mills, M nager Nuclear Regulation and Safety Subscribed pnd sworn to before ms this -r

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'~ day of ra ~~t 1980.

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Notary Public

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My Commission xpires Enclosure

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ENCLOSURE

RESPONSE

TO D. G.

EISENHUT'S LETTFR DATED OCTOBER 31, 1980 POST-TMI REQUIREMENTS BROMNS FERRY NUCLEAR PLANT DOCKET NOS. 50-259, 50-260, 50-296 The enclosure provides TVA's response for the Brooms Ferry Nuclear Plant to the clarification items listed in Enclosure 1 to D. G.

Eisenhut's October 31, 1980, letter regarding. post-TMI requirements.

Attachment A contains a list of the outages for the Emergency Core Cooling Systems for the last five years.

Attachment B contains the training program requirements for the shift technical advisors.

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I.A.l.l Shift Technical Advisor technical advisors.

These individuals have completed a formalized training program, attached, which is specifically formulated for STA's.

We have reviewed the TVA program with the INPO program and find that the basic programs, including qualifications, are consistent.

TVA reserves the right to specifically adapt our STA training to suit our particular goals't this time, we anticipate no major changes to the current program for use in the long term.

The training program will be reviewed and improved in accordance with our usual program assessment and feedback channels as our experience with this STA position evolves.

We are experimenting with a 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months shift schedule with the STA's.

We expect that improved shift-to-shift continuity will be observed, and that -human factors problems associated with the standard rotating shift may be alleviated.

TVA submitted technical specifications including STA's as part of the basic shift staffing on September 9, 1980.

The proposed amendment has not been approved to date.

Z.A.1.3 Shift Manning Implementation 1.

The overtime requirements have been implemented insofar as present staffing and commitments allow.

2.

The July 1, 1982 implementation date for staffing may be difficult or impossible to meet due to, a) higher than normal attrition rates of licensed operators due to various factors within the industry and b) recent experience with license examinations indicate fundamental changes in NRC examining procedures or inadequate training of personnel due to a more intensive academic approach on the examinations.

The

, combination of the above two factors will probably result in shortages of personnel in 1982 rather than the surplus over present staffing that is needed to meet the new requirements.

I.A.2.1 Immediate Upgrading of RO and SRO Training and Qualification 1.

SRO required experience for license.

The applicants for SRO licenses are Assistant Shift Engineers (ASE) or Shift Engineers (SE).

The TVA power plant experience requirement for these two operator classifications is as follows:

A.

Assistant Shift Engineer four years'inimum.

B.

Shift Fngineer five years'inimum.

In addition to the above, TVA requires that any SRO license applicant's experience shall include two years'uclear experience with at-least six months at the facility for which the license is requested.

Precritical applicants will be required to meet unique qualifications designed to accommodate the fact that their facility has not yet been in operation.

2.

SRO's must be RO's one year.

TVA requires that all applicants for SRO licenses shall have held a reactor operator (RO) license for at least one year except as specified for precritical applicants.

3.

Three months on shift as extra man.

TVA's SRO.training program includes a three-month period of shift training as an extra SRO on shift.

TVA's hot license program includes a three-month period of training during which the license applicant is assigned to a control room as an extra operator on shift.

4.

Modify training.

A.

The TVA cold and hot license and requalification programs provide training in heat transfer, fluid flow, and thermodynamics.

B.

The TVA cold and hot license and requalification programs include training in the use of installed plant systems to control or mitigate an accident in which the core is severely damaged.

C.

The TVA cold and hot license and requalification programs adequately emphasize reactor and plant transients.

Additional information on training modification is provided in response to item II.B.4.

5.

Facility certification.

TVA meets this requirement in that the Director, Division of Nuclear Power, signs all license certifications.

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I.A.2.3 Administration of Training Programs simulator instructors and plant instructors (at plants which have licensed SRO's) involved in the cold and/or hot license and requalification programs are required to successfully complete an SRO examination.

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I.C.1 Short-term Accident and Procedures Review 1.

Small Break LOCA TVA has complied with this item as required.

2.

Inadequate Core Cooling TVA is actively participating with the BWR Owners'roup in developing programs to comply with this requirement.

We understand that NRC has been reviewing the progress of the Owners'roup in this area and has been largely satisfied.

NRC questions outstanding are actively being pursued.

At this time, all submittals will be provided through the BWR Owners Group.

As

required, none of the guidelines or procedures will be implemented until approval by the NRC has been obtained.

However, TVA is currently evaluating the new procedures at the Browns Ferry simulator and we may ask for early approval.

3.

Transients and Accidents - Same as item 2 above.

I.C.5 Feedback of Operating Experience operating experience to the plants and training programs meets the intent of the NRC position.

TVA is continuing to review associated industry programs, like the INPO/NSAC, SEE-IN, to determine the program modifi-cations necessary to eliminate duplication while ensuring that all pertinent information is reviewed.

I.C.6 Verify Correct Performance of Operating Activities revised our procedures in the area of equipment control.

TVA currently controls equipment in accordance with paragraph 5.2.6 of ANSI N18.7 (1976).

We will provide detailed comments to the proposed new revision to Regulatory Guide 1.33 when such comments are formally solicited.

In

general, our means of compliance with the five supplemental requirements to be included in this revision of Regulatory Guide 1.33 are as follows:

I 1.

All equipment control is in accordance with paragraph 5.2.6 of ANSI N18.7-1972 (1976 rev.) regardless of why the equipment status is changed.

This includes equipment removed from service for surveillance tests.

2.

TVA clearance procedures require all equipment to be released from service to be authorized by an SRO.

Troubleshooting or minor repairs may be authorized by the RO.

Routine surveillance testing is authorized by the RO and is performed in accordance with approval checklist and procedures.

The SRO is kept informed of activities on the unit by the RO.

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TVA has reviewed its equipment control measures and determined that where necessary a second qualified person verifies correct implementation.

These include verification of locked valve positions in safety systems and temporary alterations.

Other procedures require extensive check-lists and interaction with other staff personnel.

These include systems checklists, shift turnover, unit prestart and panel checklists.

Pro-cedures to disable safety related equipment for maintenance are imple-mented by an SRO and require that each component involved in a clearance, be written out on the clearance sheet.

This sheet is reviewed by the shift engineer before the clearance is issued.

Each card used to identify a component in t'e clearance is accounted for.

Limiting con-ditions for operation require redundant systems be tested while a component is removed from service.

Following maintenance, safety related equipment is tested to ensure satisfactory performance prior to being declared operable.

4.

5.

Equipment status is not changed without approval of the RO.

Plant operating instructions require completion of a startup checklist prior to unit startup.

This checklist is used to verify correct align-ment of all safety systems.

In addition, alignment of critical systems is reviewed each shift.

Anytime a critical component is changed from its normal position or condition, a system status sheet is completed and placed in a system status folder.

Panel checklists are reviewed each shift to verify proper panel alignment exists for all safety systems.

Second verification of system alignment is provided where needed.

=-It is TVA's opinion that this verification function can be per'formed ade-quately by an assistant unit operator.

(AUO) and that the use of licensed unit operators is not necessary.

The AUO has sufficient training and familiarity with, plant systems to ensure correct system alignment, and this policy will allow the licensed operator to remain in the control room.

In summary, we believe that our procedures for control of equipment are fully adequate and meet the intent of the supplemental requirements.

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I.D.1 Control Room Design Review NUREG-0700.

I.D.2 Plant Safety Parameter Display of the final NUREG-0696.

Our preliminary assessment is as follows.

1.

The main control room panels are the operator's chief source of information and the SPDS should provide only supplemental information.

Accordingly, the basic design of the SPDS should be premised toward an informational format.

2.

We see little benefit in having an SPDS in the technical support center and emergency operations facility, particularly considering the volume of other information required to be available in the TSC and EOF.

3.

The availability requirements of the SPDS are grossly inappropriate considering the functional purpose.

II.B.1 - Reactor Coolant Systems Vents that the Browns Ferry existing reactor venting capability is fully satisfactory.

The )ustification for our position was presented to NRC during the October 11, 1979, topical meeting and is also contained in the BWR owners'roup submittal in response to NUREG-0578.

The existing Browns Ferry reactor venting system is represented accurately in the BWR Owners'roup submittal.

Also, there are no other systems, such as isolation condensers, which are sub)ect to loss of function due to the inability to remotely vent noncondensible gases.

II.B.2 Design Review of Plant Shielding and Environmental Qualification of Equipment for Spaces/Systems which may be Used in Post-Accident Operations in a post-accident situation.

Electrical equipment qualification is addressed by TVA's response to IE Bulletin 79-01B.

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II.B.3 Post-Accident Sampling Facility W

The PASF will be located in the turbine building and will serve all three Browns Ferry units.

Samples will be taken from the following points.

1.

Reactor coolant recirculation loop A.

2.

Reactor coolant recirculation loop B.

3.

Drywell atmosphere.

4.

Torus atmosphere.

The Browns Ferry design will consist of an online system as the primary system with backup grab sample capability.

The installation of the facility constitutes a major modification and we do not expect to be complete until mid-1982.

The design appears to be compatible with NRC criteria except in the following areas.

Containment hydrogen monitoring will be performed by separate instrumentation specified in item II.F~ 1.

2.

We see no basis for requiring chloride samples and accordingly do not intend to provide for such.

3.

We have no current plans to provide boron analysis capability.

4.

Since one facility will serve all three units, some sample lines will be lengthy.

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0 II.B.4 Training for Mitigating Core Damage TVA is presently developing the Mitigating Core Damage training program for the shift technical advisors and operations personnel from the operations supervisor to the licensed operators to comply with Enclosure 3 of H. R. Denton's March 28, 1980, letter.

An abbreviated program of the operator training is being developed for managers and technicians in the Health Physics, Plant Chemistry/Radiochemistry, and Instrumentation and Controls Sections commensurate with their responsibilities in the event of a core damaging accident.

We expect to have the fundamental training program developed by January 1,

1981, and the comprehensive program developed to allow implementation by April 1, 1981.

We expect completion of the initial training program by January 1,

1982.

II.D.l Relief and Safety Valve Test Requirements concurs with the findings and recommendations of the BWR Owners'roup, and we will continue working with the Owners'roup in implementing'he test program.

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II.D.3 Direct Indication of Relief and Safety Valve Indication NUREG-0578 category A, item 2.1.3.a.

We contest the need for technical specifications on this item as follows.

1.

The original installation was performed under 10 CFR 50.59 as requiring no change in technical specifications (no preimplementation,review).

2.

Two separate systems exist to monitor relief valve position which, in combination, are highly reliable.

3.

The installed system is mainly diagnostic.

Operator action in case of malfunction is not dependent on the operability of the position indicating instruments but rather from other symptomatic indicati'ons.

4.

The systems have no automatic function.

The model technical specifications provided to BWR licensees on July 2, 1980, are considerably more limiting than what we consider necessary.

Since the modifications were performed in a very short time frame as required by NUREG-0578, little consideration was given to on-line maintenance capability as is normally done.

If the model technical specifications were adopted, unnecessary outages may result.

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~5 II.E.4.1 Dedicated Hydrogen Penetrations regard to NRC clarifications for adherence to single failure since we do not use dedicated penetrations.

Our initial review has indicated the following.

The basic design meets single failure criteria except for part of the vent side system.

On the vent system, there is a primary and a backup vent valve alignment.

The primary vent path is single failure proof,

however, the backup arrangement is not.

We wish to discuss the accepta-bility of this type of arrangement in the near future with appropriate members of your staff.

P I

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II.E.4.2 Containment Isolation Dependability exception of item 4 on Browns. Ferry unit 1 regarding ganged resetting of certain isolation valves.

This logic arrangement was incorporated by TVA to satisfy NUREG-0578 category A requirements on this item.

NRC subsequently disapproved this method.

Browns Ferry units 2 and 3 completed the modifications necessary to correct this in the fall of 1980 after receipt of needed equipment.

Installation of the same modification on'nit 1 would require an unscheduled outage of approximately two weeks at

.considerable expense to TVA.'e therefore intend to complete the Browns Ferry 1 modifications during the regular refueling outage scheaulea to begin in April 1981.

In the interim until the unit 1 change is incorporated into the logic, procedural controls will be maintained as necessary to prevent automatic change of status of isolation valves after the containment isolation signal has been cleared.

Regarding position item 5, Browns Ferry currently uses a setpoint of not greater than 2.5 psig.

Considering the size of the primary containment, and a normal operating pressure of greater than 1.3 psig, this value is very sensitive and considered to bejthe minimum operationally Practical in order to avoid inadvertent containment isolations.

Regarding position item 6, NRC has previously acknowledged the acceptability of TVA's commitment to the "Interim position on containment purging and venting" in your September 10, 1980, letter to H. G." Parris from T. A.

Ippolito.

We have committed to installing valve stops at 50 valve travel.

Pending installation of the stops on each unit, we have volun-tarily restricted gur purge operations to whenever reactor piessure is 0

less than 30 lb/in (274 F).

We have performed analyses which support this operational mode and are prepared to defend our position with regard t'o item 5 and clarification item 7.'rowns Ferry currently has primary containment isolation logic which will close the containment purge valves when high radiation is sensed in the containment exhaust ducting.

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II.P.l.l Noble Gas Effluent Monitor this requirement.

This involves a temporary installation to satisfy the intent of the action item requirement and a later permanent installation in early 1982 that is dependent upon qualified instrumentation procurement and delivery.

II.F.1.2 - Sampling and Analysis of Plant Effluents equipment to adequately implement this item.

Therefore, we are not able to commit to the NRC schedule at this time.

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II.F.1.3 Containment High Range Monitor unit 1 and 3 barring any unforeseen equipment procurement delays that would preclude installation during scheduled 1981 outages.

Unit 2 will be implemented during the spring 1982 scheduled outage.

This response is based on present design and vendor information.

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IX.F.1.4 Containment Pressure unit 1 and 3 barring any unforeseen equipment procurement delays that would preclude installation during scheduled 1981 outages.

Unit 2 will be implemented during the spring 1982 scheduled outage.

This response is based on present design and vendor information.

IX.F.1.5 Containment Water Level unit 1 and 3 barring any unforeseen equipment procurement delays that would preclude installation during scheduled 1981 outages.

Unit 2 will be implemented during the spring 1982 scheduled outage.

This response is based on present design and vendor information.

II.F.1.6 Containment Hydrogen II.F.2 Instrumentation for Detection of Inadequate Core Cooling in this area.

TVA does not intend to singularly proceed any further in design on this item until final approval of Regulatory Guide 1.97 since all of the associated instrumentation is required to be qualified per this Regulatory Guide.

After approval of Regulatory Guide 1.97, design work will continue and the NRC will be notified of an implementation schedule dependent upon equipment availability and outage schedule.

The current vessel water level measurement system employed by BWR's is extensively described in NED0-24708.

II.K.3.3 Reporting SV and RV Failures and Challenges challenges as part of their annual report to NRC beginning with the report for 1980.

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0 II.K.3.13 Separation of High Pressure Coolant Injection and Reactor Core Isolation Cooling System Initiation Levels Analysis and Implementation separation of HPCI/RCIC level setpoints has no substantial benefit.

TVA concurs that auto restart of RCIC may be beneficial and readily achievable.

Current preliminary design is similar to that suggested in the BWR owners'roup response;

however, TVA will not meet the July 1, 1981, date for implementation due to difficulty of class IE equipment procurement.

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II.K.3.15 Modify Break Detection Logic to Prevent Spurious Isolation of High Pressure Coolant Injection and Reactor Core Isolation Cooling logic.

RCIC will be modified to prevent inadvertent system isolation.

This modification may not be completed byJuly 1, 1981, due to procurement of qualified equipment and delay of vendor estimates on delivery dates.

II.K.3.16 Challenges and Failures to Relief Valves

/

on units 2 and 3 (units 2 and 3 will be modified in the future to add two valves) with offset actuation setpoints to minimize the number of valve openings per challenges.

In addition, we have lowered the MSIV isolation level setpoint by 20 inches and raised the R/SV setpoint by 20 psi.

The former modification significantly reduced reactor vessel isolation and subsequent relief valve actuation, by giving the operator additional time to manually initiate high pressure in]ection systems or return the feedwater system to service prior to vessel isolation.

The Owners'roup is preparing a generic report on this item and TVA will base further actions on this item on the results of that report.

ZI.K.3.17 ECCS Outages

RCIC, RHRSW, and the Diesel Generator system giving the outages and their causes for the last five years.

There were no ADS outages.

TVA will continue to work with the owners'roup to improve system reliability and minimize ECCS system outages.

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II.K.3.18 Modification of Automatic Depressurization System Logic Feasibility for Increased Diversity for Some Event Sequences the feasibility and risk associated with the elimination of the need for manual actuations during specific events.

Any further actions will be based on this study.

II.K.3.21 Restart of Core Spray and Low Pressure Coolant Injection Systems a restart for LPCI or core spray on reactor low level has more disadvantages than accrued improvement in safety.

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II.K.3.22 Automatic Switchover of Reactor Core Isolation Cooling System Suction Verify Procedures and Modify Design of RCIC suction from the condensate storage tank to the suppression pool is unnecessary.

Adequate time to perform the switchover manually exists for events where RCIC is needed.

During events that require significant amounts of high pressure coolant injection, the 5000-gpm HPCI system is relied upon to provide the required coolant makeup.

RCIC is not relied upon during this circumstance due to its relatively low flow capacity (600 gpm);

Failure of HPCI to operate would result in operation of the automatic depressurization system and the low pressure infection systems.

Therefore, RCIC is not needed during events requiring large amounts of high pressure coolant injection.

While both HPCI and RCIC initiate at the same level setpoint, procedures exist to secure the HPCI relatively early during events that require small amounts of high pressure coolant infection.

.This ensures that a large amount of water in the 375,000-gallon capacity condensate storage tank is available for the low flow ('600 gpm)

RCIC system.

The large volume available to the RCIC suction gives the operator considerable time to check condensate storage tank level and perform manual switchover of RCIC suction source if conditions warrant.

Therefore, TVA feels that the addition of an automatic switchover of RCIC suction source is unnecessary and existent procedures are fully adequate.

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II.K.3.24 Confirm Adequacy of Space Cooling for HPCI and RCIC Systems to the staff.

Il.K.3.25 Effect of Loss of Alternating Current on Pump Seals of coolant to the Reactor Recirculation Pump Seal Heat Exchanger.

The Reactor Building Closed Cooling Water (RBCCW) pumps which supply this coolant are powered by diesel generators in the event offsite power is lost.

There are two RBCCW pumps per unit and each pump is powered from a seperate diesel generator.

Xn addition, the control rod drive pumps (CRD) can provide adequate cooling water to the seal if both RBCCW pumps failed to operate.

On units 1 and 3 one CRD pump is powered by a shutdown board which is fed from a diesel generator if offsite power is lost.

II.K.3.27 Common Reference Level and other concerned plant personnel, and we do not find from our study that present vessel level indications are confusing.

Furthermore, each control room has a vessel level instrument range chart "posted on the control panel which can be used to quickly interrelate any level measurement.

Accordingly, we do not intend to make any modifications.

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II.K.3.28 Verify Oualification of Accumulators on Automatic Depressurization System Valves item.

Any further actions will be based on this study.

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II.K.3.30 Revised Small Break LOCA Methods to Show Compliance with 10 CFR 50, Appendix K Company, is the most appropriate party to work with the staff in resolving staff concerns with small break LOCA models for BWR's.

The staff was informed of this fact in the September 22, 1980, clarification meeting in Washington, DC, and they indicated that this was acceptable.

Accordingly, the staff should direct their questions regarding the scope and schedule for this requirement to General Electric (attn.

R.

H. Buchholz, Manager, BWR Systems Licensing).

Copies of correspondence on this item should be sent to TVA so that we may remain cognizant of the pr'ogress of the program to resolve the staff's concerns on this requirement.

GE has informed us that they will be prepared to discuss the approach to this item.

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II.K.3.30 - Revised Small Break LOCA Methods to Show Compliance with 10 CFR 50, Appendix K Company, is the most appropriate party to work with the staff in resolving staff concerns with small break LOCA models for BWR's.

The staff was informed of this fact in the September 22, 1980, clarification meeting in Washington, DC, and they indicated that this was acceptable.

Accordingly, the staff should direct their questions regarding the scope and schedule for this requirement to General Electric (attn.

R. H. Buchholz, Manager, BWR Systems Licensing).

Copies of correspondence on this item should be sent to TVA so that we may remain cognizant of the progress of the program to resolve the staff's concerns on this requirement.

GE has informed us that they will be prepared to discuss the approach to this item.

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II.K.3.31 Plant Specific Calculations to Show Compliance with 10 CFR 50.46

II.K.3.44 Evaluation of Anticipated Transients with Single Failure to'erify No Fuel Failure generic study.

Preliminary analysis indicates that for anticipated transients (including transients which result in a stuck-open relief valve) combined with the worst single failure and assuming proper operator actions, the core remains covered.

Upon completion of the Owners'roup

study, the results will be provided to the staff for review.

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II.K.3.45 Evaluation of Depressurization with Other than Automatic Depressurization System This analysis showed that:

1.

Rapid depressurization is best.

2.

A full ADS blowdown is within the design basis of the reactor pressure

vessel, and the vessel fatigue is not substantially reduced by a slow depressurization.

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II.K.3.57 Identify Water Sources Prior To Manual Activation Of ADS of low pressure water sources prior to manual actuation of ADS.

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III.A.1.2 Upgrade Emergency Support Facilities clarification is provided by the NRC staff in NUREG-0696.

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III.A.2 Emergency Preparedness submitted by January 2, 1981.

TVA plans to comply with (milestone 2) submittals due March 1, 1981, and the implementation of plans (milestone 3) due April 1, 1981.

We will continue to develop and upgrade the REP metero'-

logical programs and provide descriptions and implementation schedules pertaining to milestones 4-8 following issuance and review of the revised NUREG-0654.

III.D.l.l Integrity of Systems Outside Containment Likely to Contain Radioactive Material for Pressurized Water Reactors and Boiling Water Reactors as required by NUREG-0578, recommendation 2.1.6.a.

We do not feel, however, that requirements indicated in the supplied model technical specifications should be a licensing condition and accordingly have not submitted a technical specification change.

III.D.3.3 - Inplant Radiation Monitoring radio-chemical lab with existing equipment.

If unexpectedly high back-ground radiation levels

~after an accident preclude the use of equipment in the area, TVA has implemented procedures which consist of removing the multichannel analyzer, calculator, spectroscopy amplifier, and other associated equipment from the radio-chemical laboratory and proceeding to the west end of the intake building where a power supplj" and shielding cage is located.

The components can be assembled, calibrated, and ready to analyze inplant samples in a short time.

In the long term, iodine sampling requirements, will-be satisfied with equipment in the post-accident sampling facility.

III.D.3.4 - Control-Room Habitabili.ty Requirements evaluation by January 1,

1981.

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ATTACHMENT A EMERGENCY CORE COOLING SYSTEM OUTAGES

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II.K.3.17 DIESEL CEhVRATORS UNIT 1

& 2 1&2 162 162 1 6 2 162 1&2 1&2 1 6 2 1

& 2 1 &2 1&2 1&2 1

& 2 DATE 1/14/76 11/3/76 11/26/76 7/9/78 11/6/78 10/9/79 10/12/79 ll/13/79 11/20/79

.-, 2/7/80 2/8/80 2/12/80 10/2/80 10/6/80 10/29/80 OUTACE LENGTH 17 hrs.

43 nin.

=30 r4in 50 nin.

7 hrs.

25 c4in.

9 days, 30 r4in.

1 day, 12 hrs.

15 nin.

1 day, 13 hrs.

30 t4in.

1 day, 14 hrs.

1 day, 3 hrs. ~ 20 nin.

23 hrs.,

45 nin.

7 hrs.,

50 nin.

3 days, 23 hrs.

2 days, 21 hrs.,

30 nin.

1 day, 3 hrs.,

20 rtin.

DESCRIPT IO.'s Diesel Cenerator D failed nonthly SI.

Diesel Generator D exhibited erratic behavior.

Diesel Generator B start circuit breaker was found inoperable during r4aintenancc test.

Field breaker on diesel generator C tripped in hot standby due to thermal heating.

C diesel Stol 1 relay bad.

Annual inspection on A diesel.

Annual inspection on B diesel.

Annual inspection on C diesel.

Annual inspection on D diesel.

Diesel C inoperable.

Diesel D inoperable Diesel C inoperable Annual r4aintenance on A diesel.

Annual t4aintenance on B diesel.

Annual r4aintenance on C diesel.

CAUSE Hydraulic actuator of diesel governor did not respond properly due to low oil and r4isadgustncnt.

Dirty oil in hydraulic actuator.

Broken stud holder on connector of breaker.

Protective louvers on control cabinet had been bent into fan blade while rer4oving scaffolding, rendering the cooing fan inoperable.

Bad relay.

Maintenance inspection.

Haintenance inspection.

Maintenance inspection.

Testing Testing Testing Maintenance inspection.

Haincenance inspection.

Haintenance inspection.

0

DIESEL GENERATORS UNIT 3

3

'ATE 11/26/76 4/21/77 "

9/19/77 9/22/77 11/21/77 7/6/78 7/6/78 11/24/78 OUTAGE LENGTH Not available 9 hrs.,

36 min'.

17 hrs.,

10 min.

14 hrs.,

30 min.

Not available 7 hrs.,

20 min.

4 hrs.,

45 min.

Not available DESCRIPTION Diesel generator 3D start circuit 1 found inoperable during SI.

3B diesel lube oil pump will not run.

Diesel generator 3D tripped on overspeed during testing.

3D diesel dirty oil.

3B diesel air start system would not start in alloted time, 3C diesel breaker wi'll not operate.

3D diesel ECR relay bad.

3B diesel lube oil circulating pump inoperable.

CAUSE Relay failure in speed sensing circuit.

Bad motor bearings.

Open fuse in exciter field circuit Operation.

Rust in air lines.

Charging motor shorted and micro switches burned up.

Bad ECR agastat.

Bad bearings 12/2/79 2 days, 16 hrs.,

30 min.

Diesel generator 3C tripped following start of RHR pump during I ad acceptance test.

Setpoint drift in frequency generator circuit caused diesel to tie on at too low of speed and voltage.

1/17/80 Not available Diesel generator 3A lost spccd control while testing in accordance with I b E Bulletin 79-23.

Bioken coupling in speed pick-up.

3

.2/13/80 2/19/80 2/22/80 3/25/80

'/28/80 4 day, 7 hrs.

1 day, 18 hrs. '

hrs.

~ 45 min, Diesel 3A inoperable Diesel 3B inoperable Clean coolers in 3D diesel 23 hrs.,35 min.

Diesel 3B inoperable 3 days, 6 hrs.,

5 min.

Diesel 3A inoperable Testing Testing Clams in coolers.

Testing Testing.

DIESEL GENERATORS DATE 3/31/80 4/2/80 4/2/80 4/29/80 5/1/80 5/13/80 6/3/80 6/9/80 OUTAGE LENGTH 1 day, 5 hrs.,

45 min.

7 hrs.

1 day, 1 hr.,

15 min.

4 hrs.,

15 min.

Noc available 2 hrs.,

45 min.

2 hrs.,

35 min.

18 hrs.,

30 min.

DES CRIPTION Diesel 3D inoperable.

Diesel 3B inoperable.

Diesel 3C inoperable.

Diesel 3A inoperable.

Diesel generator 3B governor actuator vould noc respond properly during SI.

Diesel 3D inoperable.

Diesel 3A inoperable.

Diesel generator 3B auxiliary oil pump motor tripped.

CAUSE Testing.

Testing.

Cause unknoun.

Suspect oil contamination.

Test run successfully after flush and oil replacement.

Testing.

Morn motor bearings.

6/11/80

- 6/18/80 7/3/80 8/5/80 9/4/80 9/15/80 2 hrs.

~ 50 min.

Diesel 3A inoperable.

3 days, 1 hr.,

25 min.

1 day, 15 hrs.

Not available Diesel 3A inoperable.

Scop circuits not correct on 3A diesel.

Diesel generacor 3A uould not trip to idle speed from a loaded condition during monthly SI.

1 day, 23 hrs.,

20 min.

Diesel 3C inoperable 1 day, 17 hrs.,

45 min.

Diesel 3D inoperable Not available Not available Tescing.

Testing.

Governor malfunctioned.

Sheared gear in speed governor.

10/2/80 5 hrs.,

20 min, Diesel 3A inoperable.

Testing

DIESEL GENERATORS DNIT 3

10/10/80 11/5/80 OUTAGE LENGTH 3 hrs.,

35 nin.

3 hrs.,

30 nin.

DESCRIPTION Diesel generator 3B nein lube oil p~

was inoperable.

Diesel 3A inoperable.

Bearings locked up in punp due to nornal veer.

Testing.

f r

RESIDUAL HEAT REGAL SERVICE HATER SYSTEM DATE 11/16/76 2/10/77 7/7/77 2/6/78 5/22/79 3/6/80 4/11/80 4/21/80 5/15/80 5/28/80 6/3/80 8/13/80 8/22/80 9/27/80 OUTAGE LENGTH 1 day, 20 hrs.,

30 nin 28 hrs.,

20 nin.

50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months (punp Al) 1 hr.,

20 nin.

4 hrs.

Hot available 6 days, 15 nin.

5 days, 23 hrs. ~

45 nin.

1 day, 20 hrs.,

5 nin.

1 day, 20 hrs.,

58 nin.

1 day, 21 hrs.,

45 nin.

6 hrs.,

45 nin.

3 hrs.,

15 nin.

18 days, 13 nin. -,

DESCRIPTIOH Bl pu"-p did not auto start on "D" D.G. Start.

Bad vent valve on C-1 pu=p.

Punp Al did not start during SI, punp Bl

'as inoperable for a nodification.

"2C" RHR heat exchanger service vater supply inoperable.

Se'al and float danaged on C-1 punp.

Hould not seal off.

Vent valve on.punp D-2 not sealing correctly.

Excessive vibration on pu"p A-l.

Excessive vibration on punp B-l.

Punp B-2 inoperable.

Punp D-1 was inoperable.

Punp D-2 was inoperable.

Leak on ball trap vent on p~ C-l.

Electrical problen on punp B-2.

Punp B-1 had lou flou during testing.

CAUSE Brush cap vibrated out of spring charging motor on breaker.

Counter veight broke on float.

Failed relay in pu=p A auto-start circuit.

Bad notor bearing in heat exchanger discharge valve.

Defective seal and float.

Leaking vent valve.

Punp vora out'.

Loose coupling.

Not available hotc 1.

Note l.

Leaking vent.

Breaker was dirty.

Punp veer.

CORE SPRAT UNIT 001 DATE I/10/80 OUTAGE LENGTH 1 day, 2 hrs.

5 min.

DESCRIPTION Loop II vas inoperable CAUSE 75-53 inboard discharge MV tagged, 75-53 manual isolation valve closed for x-ray.

001 5/12/80 16 hrs.

49 min Loop I vas inoperable.

No indication of flov to the Loop I pump room cooler from one cooling vater header.

Apparent cause vas piping blockage.

001 5/14/80 8 hrs.

45 min.

Loop II vas inoperable Oil change in motor bearing and removal of oil cooler in upper bearing.

002 5/13/80 16 hrs.

40 min.

Loop I vas inoperable.

Oil change in motor bearings and removal of oil coolers for upper motor bearing.

002 5/14/80

.13 hrs.

25 min.

Loop II vas inoperable Oil change in motor bearings and removal of oil cooler for upper motor bearing.

003 5/20/80 12 hrs.

40 min.

Loop I vas inoperable.

Oil change in motor bearings and removal of oil coolers for upper motor bearings.

003 8/ll/80 18 hrs.

45 min.

Loop II vas inoperable.

Inadequate cooling vater flov to Loop II pump room cooler due to piping blockage.

0

UNIT 001 DATE 1/4/77 OUTACE LENCTH 4 days.

10 hrs.

DESCRIPTION 1A RHR heat exchanger was inoperable due to a leak in the hear. exchanger.

CAUSE Leak at floating heat gaskez due to loose locking nuts caused by vibration.

001 3/21/77 2 days, 1 hr.

35 nin.

Loop 1 LPCI control valve was inoperable Da-"agc to valve internals (upper and lower bearings and yoke.)

001 11/28/79 Hot available RHRSW supply to RHR heat exchanger 1D was nonfunctional.

Hisapplfcation of hangez design discovered during IE Bulletin 79-l4 inspection.

001 4/11/80 5 days, 20 hrs.

40 nfn.

1A RHR heat exchanger was inoperable due to a leak in the heat exchanger.

Leak at floating head gasket causcdiby loosening of lock nuts.

001 6/21/80 001 8/12/80 002 8/15/80 4 days, 9 hrs.

1 hr. 55 nin.

6 days, 15 hrs.

30 nfn.

"IC" RHR heat exchanger was inoperable due to a leak in the heat exchanger.

1D RHR punp was inoperable 2C RHR punp fnop due to C RHR heat exchanger leak.

Leak at floating head gasket due to loose locking nuts caused by vibration.

Inadequate cooling water to punp seal heat exchanger due to plugging by aud.

Leak at floating head gasket duc to loose locking nuts caused bv vibration.

002 8/15/80 002 8/30/80 003 9/23/76 003:

2/13/78 29 days, 23 hrs.

40 nfn.

1 day, 22 hrs.

15 hrs.

17 nin 3 days, 19 hrs.

25 nfn.

2B RHR pmp fnop due to "8" RHR heat exchanger leak.

2D RHR punp inop due to "D" RHR heat exchanger leak.

3C RHR puup would not start on nornal power.

Loop 1 LPCI control valve was inoperable.

Leak at floating head gasket duc to loose lockfng nuts caused by vibration.

Leak at floating head gasket duc to loose locking nuts caused by vibration.

A cable fn the logfc was found open.

Danage to valve internals (upper and lower bearings and yoke) 003 4/28/78 18 hrs.

20 nfn.

Loop 1. LPCI control valve was inoperable.

Danage to valve internals (upper and lower bearings and yoke) 003 5/6/79 003 1/17/80 4 days, 12 hrs.

5 afn.

10 hrs.

50 nin Standby Coolant Supply (RHRSW) was isolated to Unit 3 during nornal operation.

Loop II RHR test valve tripped in nfd-position Isolation of RHRSW to 2B RHR heat exchanger toz naintenancc.

Valve scca lubricant hardened, lost lubricity, and caused valve rotor operator to tzfp on ovcrcuzrcnt.

RHR WIT 003 DATE 2/5/80 "OlJTACE LENGTH 1 day 10 hrs.

40 min.

DES GRIP TIOH Loop II RHR tesr. valve vas inoperable CAUSE Failure of a gear tooth in the limit smitch.

003 2/17/80 7 hrs.

3B RHR pump was inoperablc.

Inadequate cooling vater to pump seal heat exchanger due to plugging of valve by shells and mud.

003 5/12/80 20 hrs.

55 min.

3B RHR pump uas inoperablc.

Inadequate cooling uater to pump seal heat exchanger due to apparent restriction in the piping.

003

'7/14/80 5 hr.

35 min.

3D RHR pump tripped during surveillance testing.

Pump tripped on overcurrent due to possible inappropriate relay setpoint.Investigation continues.

003 8/9/80 10 hrs.

35 min.

3B RHR pump uas inoperable Inadequate cooling uater to pump seal heat exchanger due to piping restrictions.

~

s 9l )

UNIT 001 DATE 5/12/77 OUTAGE LENGTH.

3 days, 4 hrs, 45 nin.

HPCI DESCRIPTION HPCI would not start during surveillance testing CAUSE Auxiliary oil pu=p had defective pressure switch.

not allowing oil punp to start, which in turn prevented HPCI fron starting.

001 11/8/77 Not available HPCI turbine speed controller would not control the turbine.Loss of volrage to governor due to an open resistor.

001 7/10/79 5 days, 18 hrs.

20 nin.

HPCI failed to cone to rated speed and flow during surveillance testing.

Turbine stop valve did not fully open due to loosening of an ad$ usting screw.

001 001 001 001 10/10/79 10/11/79 10/17/79 12/03/79 4 hrs.

20 cLn 10 hrs.

40 t:in 3 hrs.

42 nin 1 day, 1 hr.

15 nin HPCI tripped during surveillance testing.

HPCI was inoperable HPCI suction supply valve frou torus ~ould not open during surveillance testing.

HPCI turbine stop valve would not stay open during survei.llance testing.

Failure of turbine exhausr. rupture disc.

Failure of turbine exhaust rupture disc.

Dirty contacts on valve linit switches.

Failure of cocpression spring in hydraulic trip nechanisn.

12/4/79 5 days, 11 hrs, 40 nin.

HPCI tripped during surveillance test.

Ovcrspeed trip problens.

'001 3/22/80 40 nin.

HPCI turbine stop valve would not open completely during surveillance testing.

Insufficient hydraulic prcssure to open valve due to worn nechanical ovcrspeed trip piston.

001 4/7/80 001 6/2/80 7 hrs.

30 ain.

2 days, 13 hrs.

10 nin.

HPCI tripped during surveillance testing.

HPCI turbine stop valve would not open conpletcly during surveillance testfng.

Failure of turbine exhaust rupture disc.

Insufficient hydraulic pressure to open valve due to worn nechanical overspecd trip piston.

001 001 7/8/80 7/29/80 21 hrs, 44 nin. j 17 hrs, 55 min.

HPCI was inoperable

~Control valve to HPCI lube oil cooler and gland seal condenser stuck closed.

Yalve guide was loose.

Punp inoperable to change oil.

)

HPCI DNIT 001 DATE 9/6/80 OUTACE LENGTH 19 hrs.

45 nin.

DESCRIPTION Mater in HPCI turbine oil, oil changed.

Cause of ~ater intrusion is still under investigation.

002 11/16/76 11 hrs.

HPCI turbine steam supply valve failed to opca during surveillance testing.

Failure in torque switch caused valve motor to trip on overload in closed position.

002 12/18/77 4 hrs.

40 nin.

HPCI flow controller left in manual node rather than in required automatic mode.

Operator left control in manual after usc of HPCI for reactor water level control following scram 002 002 6/27/78 6 days,'4 hrs.

2 nin.

1/13/79 2 days, 18 hrs.

15 nia.

HPCI high pressu're pump and reduction gear damaged duriag surveillaace testing.

HPCI turbine stean supply valve failed to open duriag surveillance testing.

Insufficient oil pressure aad lubrication due to closed valve in. oil line.

4 Hechaaical failure of valve limit switch.

002 9/27/79 22 hrs.

30 nia.

HPCI pipe retraiat found in failed conditioa.

Dakaown.

Discovered during IE Bulletin 79-02 inspection.

002 10/19/79 2 days, 8 hrs.

47 nin.

HPCI Vas inoperable due to test flow control valve being inoperable.

The prcssure seal in the valve was blown.

002 2/6/80

=

13 hrs.

HPCI was inoperable.

Perform preventative maintenance on turbine exhaust rupture disc.

002 002 2/16/80 2/23/80 10 days, 1 hr.

23 nin.

. HPCI turbine coupling bearing support. pedestal fouad cracked.

Probable. cause was water ha=et.

002 002 3/10/80 8/12/80 003 9/21/76 003 8/26/76 12 hrs.

14 nin.

12hrs.

35 nin.

"1 day, 23 hrs.

36 nin.

16 hrs.

12 nin.

~

HPCI tripped during surveillance testing.

HPCI cycled between overspeed trip and trip'reser.

during surveillance testing.

HPCI shaft drive oil pump would not maintain prcssure.

Failure of turbine exhaust rupture disc.

Failure of turbine exhaust rupture disc..

Failure of ECH due to grounded connector on governor.

Loose union on pump suction caused pump to suck air, resulting ia reduced oil prcssure.

WIT 003 DATE I/26/77 OUTAGE LENCTH 3 days, 6 hrs.-

55 min.

HPCI DESCRIPTION Restraints found with loose bolts and broken anchors following HPCI operation during reactor scrams.

CAUSE Restraints not installed as designed.

~

003 7/5/77 5 hrs.

40 min.

HPCI turbine steam supply valve failed to open during surveillance testing.

Failure in torque switch caused valve motor to trip on overload in closed position.

003 8/30/77 003 7/6/78 4 hrs.

35 min.

ll hrs.

50 min.

HPCI turbine speed controller would not control the turbine during surveillance testing.

HPCI pump tripped during surveillance testing.

Loss of voltage to governor due to an opened resistor.

Loss of voltage to governor duc to an opened resistor.

003 8/17/79 5 hrs.

14 cain.

Not available Not available.

~

0

DNIT 001 DATE 9/21/76 OUTAGE LENGTH

'0 hrs.

19 nin RCIC DESCRIPTION RCIC failed surveillance test required duc to HPCI inoperability CAUSE Halfunction of EGR.

12 001 5/02/77 1 day, 6 hrs, 35 rin.

RCIC failed to pass surveillance test in autonatic node Ra=p generator and signal converter failed ro to provide proper voltage to EGH.

001 8/1/77 15 hrs.

30 nin RCIC failed to provide rated flow in rcquized tine.

Ra=p generator and signal converter out of ad3ustncnt.

001 9/2/79 1 day, 2 hrs 30 nin.

During surveillance testina.

RCIC outboard stean supply isolation valve would not close.

To neet Tcchnical Specification rcquirencnts the inboard stean isolation valve had to be closed, rendezing HCIC

'noperable.

Valve notor failed.

Cause of failure is unknown.

001 001 10/18/79 4/2/80 9/8/76 8 hrs, 20 nin 16 hrs.

51 nin.

14 hrs.

40 nin.

RCIC was inoperable RCIC tripped during surveillance testing RCIC turbine governor speed control failed to respond during testing.

Ground on RCIC vacuun ouno notor Failure of turbine exhaus rupture disc.

Failure of turbine elctronic ovcrspeed device.

002 5/28/79 002 5/30/79 002 '/4/79 002 9/17/79 1 day, 10 hrs.

26 nin.

2 days, 19 hrs.

50 nin.

1 day, 17 hrs.

25 nin.

13 hrs.

55 nin.

RCIC electronic overspeed device could not be reset RCIC tripped on overspeed during surveillance testing.

RCIC was inoperable RCIC was inoperable Failure of turbine elctronic overspeed device Halfunction of EGR actuator caused throttle valve to zensin open.

Wheel on turbine rotor uut of center.

Check bearings and overspeed trip.

Repair baronetric condenser condensate.

Repair discharge check valve on vacuun punp.

002 10/30/79 10 hrs, 55 nin.

Not available 002 10/31/79 1 day>>

12 hrs Not 23 nin.

Not available Not avai.labia,

~ ~

~

UNIT DATE 003 10/1/76 003 7/8/78 OUTAGE LENGTH RCIC DESCRIPTION 3 hrs RCIC uould not control speed during surveillance testing 8 hrs.

45 nin.

RCIC discharge valve inoperable CAUSE 13 Broken ufre to nagnctic speed sensor.

Short cfrcuit fn indicating light assenbly had blovn fuses fn control paver circuit.

003 11/24/78 1 day, 16 hrs.

RCIC trLpped on overspced during surveillance testing.

Of 1 leak on ECR and failure of ECH and ranp generator.

003 6/27/79 3 hrs.

8 nin.

RCIC had no speed indication during surveillance testing.

Wires conncctLng nagnctfc speed sensor and ECN vcrc broken.

003 003 12/07/79 22 hrs.

20 nin 12/12/79 1 day 19 hrs.

RCIC failed to reach rated Llov during surveillance testing.

RCIC fafled to reach rated flou during surveillance testing.

DcEcctive high trfn potentio=cter in ECM.

ECH shortcd due to Lncorrect connection of ground ufre.

003 5/12/80 23 hrs.

45 nin.

RCIC tripped on ovcrspeed durLng surveillance testing.

Trip due to loss of speed control vhen diode fafled in ECN.

003 6/9/80 003 7/14/80 003 8/25/80 8 hrs.

40 nfn.

4 hrs.

35 nin.

5 hrs.

45 nfn.

RCIC tripped on overspeed during surveillance testing.

RCIC nfnfcun flou bypass valve failed to go closed during surveillance testing.

RCIC vas inoperable Trfp due to loss of speed control vhen voltage suppressor in ECN Eailcd.

Valve could not close due to dirty torque s.-itch contacts.

Ffexfble connector to speed sensing nagnetic pickup vas broken.

~

ATTACHMENT 8 TRAINING PROGRAM REQUIREMENTS FOR SHIFT TECHNICAL ADVISOR

0

1980 SHIFT TECHNICAL 'ADVISOR TRAINING FOR BFNP SECTION I " PLANT SYSTEMS Week 1

I,en th " 9 Weeks Day 1 - Introduction to Administrative Procedures A.

Duties and Responsibilities of the Shift Technical Advisor B.

Radiological Emergency Plan C.

Plant Technical Specifications D.

Control Room Access E.

Responsibilities for Safe Operation and Shutdown F.

Clearance Procedures G.

Shift Relief and Turnover A.

Instrumentation Symbols and Identification 1.

Symbols 2.

System Identification B.

Drawings 1.

Flow and Control Diagram Symbols 2.

Radiation Symbols 3.

Application of Instrumentation Symbols 4.

Mechanical Drawings 5.

Electrical Drawings Day 2 <<'ondenser Circulatin Water S stem A,

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Raw Coolin Water A.

System Design

1.

Purpose 2

~

Design Basis 3.

General

System Description

4/22/80

~ ~

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy Limiting Conditions for Operation 6.

Surveillance Requirements Raw Service Water A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes'.

Design Pressures and Temperatures 4 ~

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance, Requirements Day 3 -

Fire Protection A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 4 -

Control and Station Air S stem

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements

~g

~

Day 5-uiz and Review Week 2

Day 6-Condensate S stem A.

System Design

1.

Purpose 2.

Design Basis 3.

4 p 0

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Main Turbine A.

Description 1.

Purpose 2 ~

Principle of Operation B.

Flow Path, 1.

Main Turbine 2.

Auxiliaries 3.

Extraction Steam System C.

Abnormal Operation 1.

Water Induction 2.

Vibration 3.

Supervisory Instruments

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements EHC Pressure Control and Lo ic A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements

Day 9

Main Condenser A.

Description 1.

Purpose 2.

Principle of Operation B.

Thermodynamic Considerations l.

Affects on Cycle Efficiency 2.

Abnormal Operations Day 10-uiz and Review Week 3 Day ll-Reactor Vessel and Internals A.

System Design

1.

Purpose 2.

Design Basis 3.

General Component Description B.

System Operation 1.

Thermal Hydraulic System Design 2.

Abnormal System Conditions Reactor Vessel Process Instrumentation

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 12-Control Rod Drive S stem A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements

4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 17-Reactor Water Cleanu S stem A ~

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Reactor Buildin Closed Coolin Water S stem A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 18-Reactor Protection S stem A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements

Ir B.

System, Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Limiting Conditions for Operation 6.

Surveillance Requirements Rod Se uence Control S stem A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2,

Abnormal System Modes 3.

Design Pressures and Temperatures

~ 4 Reactor Manual Control S stem A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

I,imiting Conditions for Opera'tion 6.

Surveillance Requirements Recirculation Flow Control S ste'm A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

I ~

0

~

-10" B.

System Operation 1

~

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4,

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 20-uiz and Review Week 5

Day 21-Turbine Buildin and Service Sho Ventilation A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements

"12" Emer enc E ui ment Coolin Water S stem A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 25-uiz and Review Week 6 Day 26-Introduction to Emer enc Core Coolin S stems A.

System Design

1.

Purpose 2.

Desig'n Basis 3.

General

System Description

B.

System Operation 1.

General System Operation

.2.

Abnormal System Modes 3

~

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Hi h 4

Pressure Coolant In ection S stem

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

System Operation 1.

General System Operation 2.

Abnormal System Modes 3,

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Reactor Core Isolation Coolin S stem A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

f 11%

0

B.

System Operation 1

~

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 29-Emer enc Core Coolin S stem Wra -u A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 30-uiz and Review Week 7

Day 31-Generator A.

Description 1.

Purpose 2.

Construction B.

Operation 1.

Normal 2.

Abnormal 3.

Protection Day 32-AC Electrical S stem - Excitation A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements AC Electrical S stem - Distribution A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

4r B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and 'Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 33 - DC Electrical Distribution A.

System Design, 1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 34 - Diesel Generators A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Week 8

Day 36 - Process Radiation Monitorin S stem A.

System Design

1

~

Purpose 2.

Design Basis 3 ~

General

System Description

B.

System Operation 1.

B.

System Operation 1.

General System Operation 2

~

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements R~efueliu A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 38 -

BWR Water Chemist A.

System Design

1.

Purpose 2.

Design Basis 3.

General

System Description

B.

System Operation 1.

General System Operation 2.

Abnormal System Modes 3.

Design Pressures and Temperatures 4.

Redundancy 5.

Limiting Conditions for Operation 6.

Surveillance Requirements Day 39 - Safet Anal sis Transients 9'

Week 9

Day 41 - Radiolo ical Emer enc Plan (Site A.

General Procedure B.

Requirements and Responsibilities Day 42 - Clearance Procedure Day 43 - Technical S ecifications A.

Safety Limits Limiting Conditions for Operation Limiting Safety System Setting

'D.

Surveillance Requirements Day 44 - Administrative Procedures Day 45 - Nine-Week S stem Test Len th 1 to 10 Weeks SECTION II - PLANT FAMILIARIZATIONWALK"THROUGHS AT PLANT WITH SIGNOFF (NOT TO EXCEED 10 WEEKS) l.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

14.

15.

16.

17.

18.

19.

20.

21.

22.

23.

24.

25.

26.

27.

28.

29.

30.

31.

32.

33.

34, 35.

36.

37.

38.

39.

40.

41.

42.

43, 44.

Condenser circulating water system Raw cooling water system Raw service water Control and station air system Condensate system Feedwater system Feedwater level control Main steam system Main turbine EHC hydraulics EHC pressure control and logic Main condenser Reactor vessel and internals Reactor vessel process instrumentation Control rod drive system Reactor manual control system Rod position indicating system Recirculation system Recirculation flow control system Neutron monitoring Rod worth minimizer Rod sequence control system Reactor water cleanup system Reactor building closed cooling water system Reactor protection system Standby liquid control system Primary containment Secondary containment Primary containment isolation system Standby gas treatment system Off gas system Liquid radwaste Residual heat removal service water system Emergency equipment cooling'water system Emergency core cooling system High-pressure coolant injection system Reactor core isolation cooling system Automatic depressurization system Core spray system Residual heat removal system Emergency core cooling system wrap-up Generator Process radiati.on monitoring system Area radiation monitoring system Rev. 4/25/80

0 Length - 2 Weeks SECTION III - APPLIED HEAT TRANSFER, FLUID FLOW AND THERMODYNAMICS Week 1

Day 1

<< First Law of Thermod namics A.

Definitions Heat, work, working fluid and/or'ystem, property, state,

process, and path B.

First law for cyclic and noncyclic process (use closed system initially) 1.

Show that (}-W = hu regardless of process.

2 ~

Tabulated properties.

3.

Computation of property changes (especially for ideal gases).

4.

First law for open systems.

5. -Define enthalpy.

6.

Distinquish between equation form of first law for open system and closed system.

The open system, in steady flow, is most important in power plant work.

C.

Second law of thermodynamics 1.

Define heat engine, reversible heat engine, and discuss symbols used.

2.

Show that no heat engine is more efficient than reversible heat engine.

3.

All reversible heat engines operating between TH 6 T have c

same efficiency.

Emphasize difference between internal and external reversibility.

Celsius inequality and entropy.

4.

Irreversibility caused by friction, sudden expansion, heat transfer through finite bT, mixing processes, and others.

5.

Explain carnot cycle in detail and work example using air as working fluid and using H20 as working fluid.

Day 2 -,Steam Tables h-s dia ram T-s dia ram A.

Use of ASME steam tables and charts 1.

Define compressed liquid, saturated liquid, saturated

vapor, and superheat.

2.

How to use table 1 and table 2, how table 1

are related, compressed liquid data, define and work examples.

3.

How to use table 3.

4.

Use charts to assist in using steam tables, on p-v diagram, and constant pressure lines wet mixture, and table 2

quality, isotherms on T-s diagram.

Rev. 5/21/80

t 0

i B.

Plant processes 1.

Heating and evaporation of H20 2.

Turbine expansion 3.

Condensing 4.

Pumping processes 5'.

Flashing in valves and level controls 6.

Dump steam process 7.

Feedwater heaters, desuperheating and subcooling, and heat balance C.

Problem session Day 3 - Steam C cle Anal sis A.

Define ideal Rankine cycle and explain why it cannot have carnot efficiency.

B.

Work example for ideal Rankine cycle using saturated steam to turbine.

C.

Use one feedwater heater to reduce plant heat rate and repeat with "two feedwater heaters.

Effects of air in condenser, use of vacuum pumps, and steam jet air pumps.

E.

Moisture separator - reheater.

F.

Discuss heat balance diagram for SNP or BFNP.

G.

Problem session.

Day 4 -

Com ression of Air and Va ors A.

Types of compressors

- reciprocating, centrifugal, axial flow, lobe, vane, and radial.

B.

Compressor work per lb of fluid.

C.

Effects of temperature of entering fluid on work per lb and effect of pressure ratio on volumetric efficiency and capacity.

D.

Temperature rise during compression, explosion and lubrication

hazards, and staged compression and intercoolers.

E.

Refrigerant compressors, effects of temperatures and pressure ratio on performance, and importance of condensing temperature.

F.

Problem session.

I ~

5/pgik

'"V I and 2 - Fluid Mechanics A.

Flu.d properties II.

Dimensionless numbers 1.

Friction factor and head loss 2.

Pipe roughness factor 3.

Moody diagram C.

Energy equation 1.

Relate to energy equation in thermodynamics 2.

Sign convention and pumpwork term DE Losses in pipe fittings and equipment 1.

Nomographs by Crane and others 2.

Manufacturers performance data E,

Fluid meters and control signals 1.

Venturi tube 2.

Orifices and nozzles 3.

Fluid columns and differential pressure transducers 4.

Measuring liquid levels by using static columns of fluids a.

Description of a few industrial instrumonts used to measure depth of liquid b.

Measuring level in pressurized on pressurized water reactor plant c.

Measuring level in steam generator of pressurized water reactor plant d.

Measuring level in boiling water reactor e.

Effects of sudden changes in temperature and pressure on level indicating instruments F.

Momentum forces G.

Pump performance 1.

Energy equation 2.

Water horsepower 3.

Pump efficiency 4.

Head flow curves 5;

Net positive suction head 6.

Relating system head flow curve to pump head flow curve H.

Fluid statics 1.

Forces on submerged bodies 2.

Hydrostatic paradox 3.

Buoyant forces Incompressible vs compressible flow l.

Usual assumptions for compressible fluids 2.

Critical pressure ratio in steam nozzles and effect on mass flow rate 3.

Applications to steam jet air pumps and effects on plant performance J.

Problem session

~ ~

lt Day 3 and 4-Heat Transfer A.

Modes of heat transfer 1.

Conduction 2.

Convection 3.

Radiation B.

Definitions 1.

Heat flux 2.

Thermal conductivity 3.

Conductance and resistance C.

Heat transfer through walls l.

2.

3.

4.

5.

Plane uniform wall Introduce overall heat transfer coefficient Plane composite wall Cylindrical uniform wall Cylindrical composite wall D.

Heat transfer in pipes 1.

2.

3.

4, 5.

6.

7.

8.

q = hA (AT)

Dimensionless correlations, Nusselt

number, Reynolds number, Prandtl number, and others Parallel flow in concentric pipes, LMTD, and overall heat transfer coefficient Counterflow in concentric pipes Applications of parallel flow and counterflow Once through steam generator Shell and tube heat exchangers and corrections to LMTD Typical h values E.

Heat removal from reactor core 1.

2.

3.

4, 5.

6.

7.

8.

9.

10.

Temperature profile in fuel, normal and other Resistances due to U02, helium, cladding, and H20 Heating subcooled liquids Nucleate boiling Critical heat flux and DNB Process computer determination of MCPR Radial and axial power distribution in reactor core Local peaking factor Process computer determination of peaking factor Maximum average planar linear heat generation rate (MAPLHGR).

F.

Heat balance on reactor core 1.

Q = lQ8 (Feedwater) 2.

3.

4.

Measuring M on BWR Measuring l9i on BWR Measuring actual core flow a.

Recirculation drive flows b.

Jet pump flows c.

Core plate lE

-23" 5.

Corrections to the heat balance a.

Pumpwork b.

Cleanup c.

CRD flow 6.

Process Computer heat balance (OD-3)

G.

Problem session 9"'"

r

~24 ~

SECTION IV SIMULATOR TRAINING (BASIC SYSTEM OPERATION)

POWER OPERATIONS TRAINING CENTER Len th 3 Weeks Week 1 Day 1 Classroom A.

Procedure review 1.

Operating Instructions 85, 70 2.

Operating Instructions 69, 68 3.

General Operating Instructions 100-1 B.

Simulator 1.

Reactor startup and administrative requirements 2.

System Startup (IC-1) a.

Reactor Building Closed Cooling Water System b.

Reactor Water Cleanup System c.

Control Rod Drive System d.

Recirculating System e.

Condensate System f.

Turbogenerator Oil System g.

Steam Seal System h.

Condenser Vacuum System i.

Off Gas System Day 2 - Classroom A.

Procedure review 1.

Operating Instructions 2

2.

Operating Instructions 3

3.

Operating Instructions 47 4.

Operating Instructions 66 5.

General Operating Instructions 100-1 B.

Simulator System Startup (IC-1) 1.

Reactor Building Closed Cooling Water System 2.

Reactor Water Cleanup System 3.

Control Rod Drive System 4.

Recirculating System 5.

Condensate System 6.

Turbogenerator Oil System 7.

Steam. Seal System 8.

Condenser Vacuum System Day 3 - Classroom A.

Procedure review l.

Operating Instructions' 2.

Operating Instructions 1

3.

Operating Instructions 24 4.

General Operating Instructions 100-1 5.

Operating Instructions 92 Rev 5/8/80 B.

Simulator Reactors Startup (IC-3) 1.

Startup (surveillance instructions) 2, Pull reactor critical to heating power a.

Calculate reactor periods b.

Establish 50 F/hr heatup rate 3.

Place condensate system in long cycle Day 4 - Classroom A.

Procedure review l.

Operating Instructions 32 2.

Operating Instructions 57 3.

Operating Instructions 27 4.

General Operating Instructions 100-1 5.

Technical Specifications B.

Simulator Reactor Startup continued (IC-3) 1.

Startup (surveillance instructions) 2.

Pull reactor critical to heating power a.

Calculate Rx period b.

Establish 50 F heatup rate 3.

Place condensate system in long cycle Day 5 Classroom Ae Procedure review 1.

Operating Instructions 47, 57 2.

General Operating Instructions 100-1 3.

Technical Specifications B.

Quiz C.

Simulator 1.

Unit Startup (IC-7) 2.

Turbogenerator a.

Startup b.

Loading c.

Operating Week 2

Day 6 - Classroom A.

Procedure review 1.

Operating Instructions 18 2.

Operating Instructions 20 3.

Operating Instructions 23 4.

Operating Instructions 25 B.

Simulator l.

Unit Startup continued (IC-7) 2.

Increase power toward full load a.

Control rods

b. 'ecirculation flow Day 7 - Classroom A.

B B.

Procedure review 1.

Operating Instructions 2.

Operating Instructions 3.

Operating Instructions 4.

Operating Instructions Simulator 1.

Full load conditions 2.

Power maneuvers 30 31 34 35 Day 8 - Classroom A.

Procedure review 1.

Operating Instructions 2.

Operating Instructions 3.

Operating Instructions 4.

Operating Instructions 39 40 44 63'.

Simulator 1.

Full load conditions 2.

Decrease load and test main steam isolation valve and turbine valve Day 9-Classroom A.

Procedure review 1.

Operating Instructions 71 2.

Operating Instructions 73 3.

Operating Instructions 74 4.

Operating Instructions 75 B.

Simulator Full load conditions 1.

Emergency core cooling systems surveillance instructions 2.

Diesel generator surveillance instructions Day 10 - Classroom A.

Procedure review 1.

Operating Instructions 64 2.

Operating Instructions 65 3.

Operating Ins'tructions 66

.. 4.

Operating Instructions 67 B.

Simulator 1.

Hot startup after scram 2.

Pull critical

~

0 Week 3

Day llClassroom A.

Procedure review l.

Operating Instructions 76 2.

Operating Instructions 77 3.

Operating Instructions 78 4.

Operating Instructions 82 B.

Simulator 1.

Shutdown 2.

Controlled shutdown from full load Day 12-Classroom A.

Procedure review l.

Operating Instructions 84 2.

Operating Instructions 90 3.

Operating Instructions 91 4.

Operating Instructions 99 B.

Simulator 1.

Shutdown 2.

Emergency shutdown from full load Day 13-Classroom A.

Procedure review 1.

General Operating Instructions 100-2 2.

General Operating Instructions 100-3 3.

General Operating Instructions 100-4 4.

General Operating Instructions 100-5 B.

Simulator 1.

Power maneuvers 2.

Intergrated system response Day 14-Classroom A.

Procedure review 1.

General Operating Instructions 100-6 2.

General Operating Instructions 100-7 3.

General Operating Instructions 100-8 4.

General Operating Instructions 100-9 B.

Simulator Full load 1.

Accident conditions 2.

Transient conditions Day 15Classroom A.

B.

C.

D.

Procedure review General Operating Instructions 200-1 Review q iz Simulator Simulator exam

~ ~

~

0 SECTION V " APPLIED BOILING WATER REACTOR PHYSICS Day 1

>> Nuclear Fission:

Process and Products Light water reactor fuels

l. Initial and equilibrium core makeup 2.

Incore history of light water reactor fuels a.

Energy release b.

Fission and activation products B.

Fission energy release 1.

Types and amount of energy released 2.

Spatial distribution of release a.

Within fuel rods b.

Within coolant channels c.

Excore deposition 3.

Temporal distribution of release a.

Response

to load following b.

Shutdown C.

Fission and activation products 1.

Materials produced a.

Volatiles b.

Distribution within primary system boundary (1)

Without fuel failure (2)

With l~ failed fuel 2.

Decay heat production a.

Borst-Wheeler function b.

Dependence on operating history 3.

Hazard potential of fission products a.

Important isotopes b.

Time dependence after shutdown Day 2 " Neutron Sources Interactions and Detection A.

Source of neutrons 1.

Startup sources a.

Primary and secondary b.

Energy spectrum 2.

Fission source B.

Interactions Neutron cross sections 1.

Types and typical magnitudes in light water reactors 2.

Energy dependence and spectral effects 3.

Density effects 4.

Doppler effects and their importance C.

Neutron detection 1.

Reactor instrumentation a.

Types of detectors b.

Applications (1)

Sensitivities and ranges (2)

Incore vs excore c.

Operations (1)

Temperature effects Rev 4/25/80

0 2,

(2)

Gamma compensation (3)

Radiation damage (4)

Burn-up Detector signal processing Day 3 - Ph sics of eration and Control A.

Neutron multiplication and chain reactions (a review) 1.

Define critical, supercritical, and subcritical a.

Determining the state of a large light water reactor

b. - Measuring subcritical multiplication and shutdown margins 2.

The multiplication factor a.

The six"factor formula for keff b.

Typical values for power reactors c.

Implications for water moderated cores 3.

Reactivity B.

Reactivity coefficients for a boiling water reactor 1.

2.

Density effects a.

Moderator temperature coefficient b.

Voi'd coefficient Power defect a.

Fuel temperatur'e coefficient (1)

Doppler effects (2)

Spectral effects Moderator contributions b.

C.

Reactor control 1.

Types of controls 2.

b.

a.

Safety b.

Regulation c.

Shim d.

Power distributions Mechanisms for control a,

Control rods (1)

Operation (2)

Parameters affecting rod worths Burnable poisons D.

Core composition changes 1.

Burn-up effects a.

Changing fuel composition b.

Fission product buildup 2.

Xenon and samarium effects'.

Magnitude of the effect b.

Importance in load following E.

The interaction of control with reactivity coefficients and composition changes 1.

Short-tean changes a.

Load following in boiling water reactors b.

Xenon transients 2.

Burn-up compensation Burnable poisons I

~ t 0

Day 4 - Reactor Kinetics A.

Review of the basics 1.

Delayed neutrons a.

Beta effective in large light water reactors b.

Lifetime changes 2.

Kinetics equations 3 ~

Linear kinetics B.

Nonlinear Kinetics 1.

Reactivity feedback mechanisms 2.

Heat removal effects 3.

Transient analysis a.

Computer simulations b.

Energy releases C,

Inverse kinetics 1.

Development of the equations 2.

Reactivity computer a.

Analog computation b.

Measurement of reactivity in low power heating 3.

Inference of abnormal events by power signatures

sl 0

SECTION VI - RADIO CHEMISTRY Week 1

Day 1-Review of Basics (6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months )

A.

Modes of radioactive decay 1.

Alpha 2.

Beta 3.

Electron capture 4.

Internal conversion B.

Nuclear decay scheme 1.

Origin of gamma radiation 2.

Branching 3.

Gamma ray abundancies C.

D.

Growth and decay calculations

-1.

Constant decay 2.

Constant source 3.

Secular equilibrium -

S

- 90 r

Y Interaction of radiation with matter 1.

Alpha 2.

Beta 3.

Gamma Detection Methods (2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ) - Princi les and A

lications of Each A.

Proportional counters B.

Scintillation detectors C.

Semiconductor detectors Laboratorar Day 2-Ori in of Radioactivit in a Plant (2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months )

Fission products B.

Activation of corrosion products C.

Activation of impurities D.

Activation of water Radiolo ical Effluents (6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months )

A.

Liquids 1.

Prerelease calculations 2,

Postrelease calculations 3.

Continuous releases B.'ases 1.

Waste gas decay tanks 2.

Continuous air streams Rev. 4/25/80

aa a.

Charcoal filters b.

Particulate filters c.

Noble gases C.

Radiation monitors in effluent streams 1.

Liquids 2.

Gases a,

Inline b.

Off<<line taboratorar Day 3 - Technical S ecification Items (2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months A.

Average energy/disintegration (E)

B, Lower limits of detection C.

Basis of dose calculations Plant Chemist (6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months )

A.

Primary or radioactive side 1.

Chemistry parameter a.

Boric acid b.

LiOH c.

Hydrogen d.

Hydrazine e.

Dissolved 0

f.

Chloride an3 fluoride g.

Crud h.

pH and conductivity 2.

Radioactivity Measurements a.

Reactor coolant system (1) 100/E (2)

Iodines (3)

Fission gases (4)

Gross P-g (5)

Tritium b.

Other systems (1)

Gross P-g (2)

Tritium 0

B.

Secondary or steam cycle 1.

Chemistry parameters a.

All volatile treatment (1)

Ammonia (2)

Hydrazine b.

Dissolved 02 c.

Sodium d.

Chloride e.

Others 2.

Radioactivity a.

Gross P-y b.

Iodines c.

Noble gases taboratorar Day 4 - Considerations in Emer encies (8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months )

A.

Sampling B.

Access to facilities C.

Background radiation levels D.

Swamping of detectors E.

Contamination of counting equipment F.

Accident situations 1.

Massive fuel defects 2.

Primary to secondary leak 3.

Primary to atmosphere program 4.

Uncontrolled releases of radioactivity Laboratora Day 5 - Review and Exam (8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months )

Section VII - TRANSIENT AND ACCIDENT ANALYSIS Length 3 Weeks Week 1

Day 1 - Nuclear S stem Pressure Increase A.

Generator trip 1.

Assumptions 2.

Identification of causes and accident, description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions B.

Loss of condenser vacuum 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions C.

Turbine trip 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5,

Conclusions D.

Bypass valves failure following turbine trip - high power 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences

'4.

Results 5.

Conclusions E.

Bypass valves failure following turbine trip - low power 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions F.

Main steam line isolation valve closure 1.

Closure of all MSIV's a.

Assumptions b.

Identification of causes and accident description c.

Analysis of effects and consequences d.

Results e.

Conclusions 2.

Closure of MSIV a.

Assumpt'ions b.

Identification of causes and accident description c.

Analysis of effects and consequences d.

Results e.

Conclusions Pressure regulator failure 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions Day 2 -

Reactor Vessel Water Temperature Decrease A.

Loss of a feedwater heater 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions B ~

Shutdown cooling malfunction (RHRS) - decreasing temperature 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions Inadvertent pump start 1.

RCIC a.

Assumptions b.

Identification of causes and accident description c.

Analysis of effects and consequences d.

Results e.

Conclusions 2.

HPCI a.

Assumptions b.

Identification of causes and accident description c.

Analysis of effects and consequences d.

Results e.

Conclusions Day 3

<< Positive Reactivit Insertion A.

Continuous rod withdrawal during power range operation 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions B.

Continuous rod withdrawal during reactor startup 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions C.

Control rod removal error during refueling 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions D.

Fuel assembly insertion error during refueling l.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions Day 4 - Reactor Vessel Coolant Invento Decrease A.

Pressure regulator failure l.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions B.

Inadvertent opening of a relief valve or safety valve l.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4,

Results 5.

Conclusions C.

Loss of feedwater flow 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions D.

Loss of auxiliary power l.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions Week 2 Day 6 - Core Coolant Flow Decrease A.

Recirculation flow control failure l.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions

~,

B.

Single recirculation pump trip l.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions C.

Double recirculation pump M-G set drive motor trip 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions D.

Recirculation pump seizure l.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions Day 7' Core Coolant Flow Increase A.

B.

Recirculation flow controller failure l.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions I

Startup of idle recirculation pump l.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions Excess of Coolant Invento Feedwater controller failure - maximum demand l.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions Day 8 - Ioss of Habitabilit of the Control Room A.

Criteria for loss of habitability of the control room B.

Conditions C.

Evaluation - achievement of hot shutdown condition 1.

Reactor protection (RPS) 2.

Power supply breakers 3.

Scram pilot valves

0 Day 9 - Anal sis of Desi n Basis Accidents Control 1.

2.

3.

4.

5.

rod drop accident (RDA)

Assumptions Identification of causes and accident description Analysis of effects and consequences Results Conclusions Week 3 Day ll - Anal sis of Desi n Basis Accidents continued)

Loss of 1.

2.

3.

4, 5.

coolant accident Assumptions Identification of causes and accident description Analysis of effects and consequences Results Conclusions Day 12 - Anal sis of Desi n Basis Accidents (continued Refueling accident 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4.

Results 5.

Conclusions Day 13 - Anal sis of Desi n Basis Accidents (continued)

Main steam line break accident 1.

Assumptions 2.

Identification of causes and accident description 3.

Analysis of effects and consequences 4

~

Results 5.

Conclusions Day 14 - Environmental Conse uences of Accidents A.

Parameters used B.

Assumptions C.

Basis for regulatory guide analysis D.

Review

I" SECTION VIII-SIMULATOR TRAINING (PLANT TRANSIENTS AND MALFUNCTIONS) Len th 3 Weeks Week' Day 1 Vessel Instrumentation A.

Level B.

Pressure C.

Flows Day 2 - Scram Causes and Effects A. All automatic scrams 1.

Setpoints and reason B.

Conditions that warrant manually scramming 1.

Setpoints and reason Day 3 Emer enc Water Makeu Methods to Reactor Vessel A.

High pressure systems B.

Low pressure systems Day 4 Loss of Rx Vessel Instrumentation A.

Loss of 500 KV systems B.

Loss of 161 KV systems C.

Loss of 4 KV systems D.

Loss of 480 V systems E.

Loss of 120 V systems Day 5 - Abnormal Emer enc Shutdown A..

Standby liquid control system B.

Shutdown from backup control room 1.

Emergency operating instructions C.

Radiological Emergency Plan 1.

Liquid release 2.

Gaseous release 3.

Radiation abnormal condition Rev 5/8/80

0

~

1

~

~ 0 Week 2

Day 6 Nuclear S stem Pressure Increase A.

Generator trip (emergency operating instructions 3)

B.

Loss of condenser vacuum (emergency operating instructions 10)

C.

Turbine trip (emergency operating 3)

Day 7 - Nuclear S stem Pressure Increase A.

Bypass valve malfunction following turbine trip (emergency operating instruction 7)

B.

Main steam insolation valve clo'sure (emergency operating instructions')

C.

Pressure regulator failure (emergency operating instructions 7)

Day 8 >> Reactor Vessel Water Tem erature Decrease C.

Inadvertent pump start (emerge Day 9 - Positive Reactivit Insertion A.

Loss of feedwater heater (operating instructions 47)

B.

Shutdown cooling malfunction (emergency operating instructions 40) ncy operating instructions 38)

A.

Continuous rod withdrawal during power operation (emergency operating instructions 38)

B.

Continuous rod withdrawal during reactor startup (emergency 'operating instructions 38)

C.

Control rod removal error during refueling (emergency operating instructions 43)

Day 10 - Positive Reactivit Insertion A.

Fuel assembly insertion error during refueling (emergency operating instructions 43)

B.

Reactor vessel coolant inventory decrease 1.

Pressure regulator failure (open).

(emergency operating instructions 7) 2.

Inadvertent opening of a relief valve (emergency operating instruction '39)

l l

Week 3

Day 11 Reactor Vessel Coolant Inventor Decrease A.

Loss of feedwater flow (emergency operating instructions 2)

B.

Loss of auxiliary power (emergency operating instructions 5)

C.

Core'coolant flow decrease

'ecirculating flow control failure << decreasing flow (emergency operating instructions 31)

Day 12 - Core Coolant Flow Decrease A.

Trip of one recirculating pump (emergency operating instructions 1)

B.

Tiip of two recirculating pumps (emergency operating instructions 1)

C.

Recirculating pump seizure (emergency operating instructions 1)

Day 13 Core Coolant Flow Increase P

A.

Recirculating flow control failure - increasing flow (emergency operating instructions 31)

B.

Startup of idle recirculating pump (operating instructions 68)

C.

Excess of coolant inventory Feedwater ocntroller failure (maximum demand - emergency operating instructions 2)

Day 14 - Accident Conditions and Reco nition A.

Design basis accident B.

Rod drop (emergency operating instructions 38)

C.

Loss of coolant accident (emergency operating instructions 36)

D.

Refueling accident (fuel assembly drops in core during refueling emergency operating instructions 43)

Day 15 A.

Desi n Basis Accident I

Steam line break accident (emergency operating instructions 11 and 15)

B.

Quiz over past three weeks

0 SECTION IX - MANAGEMENT AND SUPERVISORY SKILLS Len th -

1 Week Day 1 - ~headeeehi A.

What leadership is B.

The management foundation C.

The laws and principles of self-management D.

The laws and principles of people management E.

Interpersonnel communication 1.

Two-way personal communication 2.

Transmission of facts and feelings 3.

Empathic listening 4.. Conveying meaning to others 5.

Giving instructions Day 2 - Command Rs onsibilities and Limits A.

Who is in charge?

B.

How is authority given?

C, What, are the policies and procedures?

Day 3 - Motivation of Personnel A.

Understanding human behavior B.

The priorities of people C.

What motivates people to follow leadership?

D.

Problem analysis 1.

Situation management 2.

Problem analysis guide Day 4 - Decisional Anal sis A.

Diagnosis

- A prerequisite for sound decisions B.

Comparing courses of action C.

Making the choice Day 5 - Final Examination Rev. 4/25/80

BROWNS PERRY NUCLEAR PLANT SHIFT TECHNICAL ADVISOR REQUALXFICATXON TRAINING PROGRAM X.

Classroom Training Day B.

1 ~

2.

3.

Day l.

2.

3.

4, Changes made during 1979 (including PCXS changes)

Short periods Thermal dynamics Mater makeup methods to reactor vessel Review OX 2, 3, 71, and 73 Review EOI 41 Thermal dynamics C.

Day 3 1 ~

2.

3 ~

4.

Feedwater level control OI 2 and 3, and GOX 100-1 EOI 2, 8, and 16 Thermal dynamics D.

Day 4 1 ~

2 ~

3 ~

4, 5.

Reactor manual control system and RPIS EOX 22 OX 85 Tech Spec Table 3.2.C Thermal dynamics E.

Day 5

1 I 2.

3 ~

4, Primary containment isolation system EOX ll, 13, and 15 Tech Spec Table 3.7.A Thermal dynamics F.

Day~6 1.

Recirculation flow control system 2.

Review OI 68 3.

Review EOI 1, 20, and 31 4.

Shift and relief turnover DPM No. N7904 5.

Thermal hydraulics G.

Day 1 0 2 ~

3 ~

4.

5 ~

6.

7 Diesel generators Standby auxiliary power Review OI 82 and 57 Review EOX 5, 33, and 32 Nuclear Plant STA responsibilities DPM No.

Thermal hydraulics

J

H.

Day l.

2 3.

4, 5.

6.

Residual heat removal system Review OI 74 Review EOI 40, 36, and 16 Nuclear Plant Method of Operation Policy DPM No. N7902 Review REP manual Thermal hydraulics X.

Day l.

2.

3.

4.

5e 6.

High pressure coolant i'njection Standby liquid control Review OI 73 and 63 Review EOI 9, 16, and 18 Testing for an immediate operator action in case of inadvertent contxol rod withdrawal DPM No.

BF79M13 Thermal hydraulics J.

Day 10 1 ~

2.

3 ~

4.

5.

Reactor protection system Review OI 92 Review EOX 34, 21, and 42 Nuclear Plant licensed operations shift management responsibilities DPM No. N7905 Final examination II.

Simulator Training A.

Pull criticals through heating power Various malfunctions load conditions l.

2.

3.

Various problems and malfunctions including water makeup methods to the reactor vessel Various suxveillance instruction Turbine startup a.

roll b.

synchronization c.

loading Various malfunctions on feedwater level control C.

Hot restart through critical to power 1.

2.

3.

Various malfunctions and problems=with rod blocks Various surveillance instructions Full load conditions a.

malfunctions to cause scram b.

malfunctions to cause isolations c.

scram for each student

0

D.

Pull criticals from hot restart

Various malfunctions

. E.

Complete pulling criticals from hot restart Various malfunctions F.

Full load conditions 1.

Malfunctions to cause scram 2.

Efalfunctions to cause gas conditions 3.

Scram for each trainee G.

Final examination

~I

ML18025B263

Text

Dear Mr. Denton:

RESPONSE

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