ML17250A847

TMI Action Plan (NUREG-0737) Documentation.

ML17250A847
Person / Time
Site:	Ginna
Issue date:	12/30/1980
From:	ROCHESTER GAS & ELECTRIC CORP.
To:
Shared Package
ML17250A846	List: ML17250A845 ML17250A847
References
RTR-NUREG-0737, RTR-NUREG-737 NUDOCS 8101060468
Download: ML17250A847 (85)

Text

ATTACHMENT A Rochester Gas and Electric Corporation TMI Action Plan (NUREG 0737) Documentation KI-:IILNIIII7MI',IlHfIK MW December 30, 1980

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1.A.1.1

~ ~ Shift Technical Advisor A descrxptxon of our original STA program was outlined in a letter, dated October 17, 1979, from L. D. White, Jr. to Mr. Dennis Ziemann, with additional information .

provided in a letter dated December 28, 1979, from Mr. White to Mr. Ziemann. In response to the NRC's letter dated July 7, 1980, from Mr. Dennis Crutchfield we provided additional clarification of our original STA program and a description of our new STA program in a letter dated August 5, 1980 from L. D. White, Jr. to Mr. Crutchfield.

Our original STA program utilized licensed operators and included their participation in college-level engineering courses to provide them eventually with an engineering degree. At the request of the NRC RG&E modified the original program and assigned either degreed engineers or SRO's as STA, and assigned degreed engineers to perform the Operational Assessment function.

We began staffing the Operational Assessment, Group in the summer of 1980.

Our STA training and requalification program is described by a Ginna Station Administrative Procedure, and consists of various phases as described below.

Present Level of Trainin Initial training to meet the requirements listed in Harold Denton's letter dated October 30, 1979 to All Operating Nuclear Power Plants has been completed.

This training included a four week classroom training and two day simulator training program presented by our NSSS supplier as listed below.

Title:

Chemistry/Basic Theory, Objectives and Control Objective: 1. Discuss the concerns that require chemistry control

2. Discuss the RCS/Steamside Chemistry limitations and basis

3. Discuss the techniques for main-taining chemistry limits

4. Discuss typical RCS/Steamside chemistry problems and the associated corrective actions

5. Discuss the effects of chemistry upsets on plant operations

6. Discuss chemistry indications for various accidents

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Topic Summary:

1. Functional Requirements

2. Chemistry Control Areas

3. Specifications, Limits, and Basis

4. Mechanisms for Control

5. Problems in Control

6. Chemistry Trouble Shooting

Title:

Metalurgy/Basic Fracture Mechanics Objective: Review theory of the plant limitations and operational considerations based on NSSS metalurgical restrictions.

Topic Summary:

1. Introduction

2. Fracture Criteria

3. Stress Analysis of the PWR Vessel

4. Crack Tip Stress Intensity Factor Analysis Methods of Determining Stress Intensity Factor K

5. Material Properties

6. Non-Destructive Examination

7. Codes and Standards

8. Fracture Mechanics Applications in the NSSS

9. Review of Past and Current R&D

10. Plant Specific Limits Review

Title:

Thermodynamics, Heat Transfer, and Fluid Flow and their PWR Applications Objective: Give working knowledge of the above topics at the operation level.

Topic Summary:

Basic properties of fluids and matter (energy relationships)

2. Fluid Dynamics (addresses natural circulation)

Thermodynamics and Heat Transfer (boiling) includes monitoring of temperatures, flow, pressure parameters Normal Plant Operations (as per heat generation) peaking factors as a function of primary and secondary system, management of normal reactor heat, and decay heat transfer limits (boil off is discussed)

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5. Limiting phenomena

a. burnout DNB

b. flow instability

c. sonic velocity - choked flow

d. pump runout

e. thermal transients - metal fatigue

f. fouling -

g. flashing heat stored in metal

h. blowdown to containment

i. fuel temperature DNB j.

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steam binding Zirc-water reaction

6. Accident Treatment - heat sinks and pressure/temperature limits

a. loss of RCP

b. small LOCA

c. decay heat

Title:

Nuclear Characteristics/Review Objective: Comprehensive review of the reactivity effects, magnitudes, and direction of each core reactivity coefficient and the kinetic effects of each for a typical PWR cycle, changes from cold to hot, and rod bank position.

Topic Summary:

1. Subcritical Multiplication

2. Six factor formula

3. Coefficients

4. Defects

5. Inhour equations

6. Practical Application - (measurements)

a. Moderator Coefficient

b. Power Coefficient

c. Rod Worth

7. Neutron Mechanics

Title:

Nuclear Peaking Factors Objective: Comprehensive review of F and F>H including the basis, limitations, and measurements of each.

Topic Summary:

Establish limitations of each

a. Fuel

b. Clad (includes Zr/H20 reaction)

c. Flow

2. Measurements of F and F><

3. Protection availa8le DE limitations

5. Technical Specifications

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Title:

NSSS Instrumentation; Basis, Limitations and Alternatives Objective: Define NSSS instrumentation basis, limitations and alternate sources of information.

Topic Summary:

1. Requirements and Basis for Parameter Monitoring

2. Instrumentation Limitations

3. Alternate Sources of Information

4. Believability of Information

5. Behavior During Abnormal Conditions

6. Adverse Environmental Effects

Title:

NSSS Operating Experience and System Assessment Objective: Enhance the operator's ability to establish system priorities using control room instrumentation.

Topic Summary:

1. Establish conceptual approach to operations - (normal, abnormal, and emergency)

2. Selected Industry LER's

3. Systems problems are presented;.

class must choose and set the priorities and course of action.

Title:

Normal Plant Transient Assessment Objective: Enhance the overall knowledge level of normal plant transients, including the instrumentation required, the magnitude and direction of each.

Topic Summary:

Develop a Basic Operating Plant

a. Instrumentation Required

b. Protection Required

c. Heat Balance

2. Introduction of one standard transient assessment graph (Uses, control room instrumentation ranges)

3. Step Load Changes Major Load Rejection Review of T Tref Mismatch/Re60ns

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5. Main Generator Trip Calculation of the Resultant avg 9.

Title:

Instrument Failure Assessment Objective: For any selected instrument failure, predict the magnitude and direction of each major NSSS parameter and graph.

the function assuming no operator action.

Topic Summary:

1. Class estimates response (no operator action)

2. The following failures were selected for maximum impact:

a. T Fails High at BOL

b. NSgPower Range Fails High at BOL

3. Turbine Impulse Channel Fails Low

4. Pressurizer Pressure Control Channel Fails High

5. Pressurizer Level Control Channel Fails High/Low Each calculation is concluded when either the plant has tripped or a stable reactivity balance exists.

Note: As student experience/training and time'ermit all inputs to the following major control 'systems and their failures will be discussed;

1. Reactor Make-up Control

2. Steam Generator Water Level Control

3. Electro-Hydraulic Control System 10.

Title:

Accident/Transient Assessment Objective: Enhance the ability for prompt recognition of major accident, transients and establish the basis for the appropriate emergency procedures.

Topic Summary:

Rod Withdrawal Accidents (FSAR)

a. Review Protection (DNBR Vs. pcm/sec.)

2. Main Generator Trips (FSAR)

3. Natural Circulation, Detailed

a. S/G b, T Calculations

b. Power to Flow Ratio

c. Decay Heat,

d. Subcooling

4. Basis for Stopping RCP's on Low Pressure

a. Mass Inventory

b. Steam Generator Pressure (Bounding Limit)

5. S/G Tube Rupture

a. Impact of Closing the MSIV

b. Methods of Depressurizing

c. Monitoring Subcooling

d. Conditions for Stopping SI

e. Conditions Requiring Closing of PORV

6. One PORV Open on Pressurizer

a. Details of the Level Response

7. Small Break Transient Behavior Modes

a. < 3/8" to > 2"

b. Conditions for Stopping SI

8. Steam Break

a. FSAR and Generic Analysis

b. Calculate RCS Temp. for 1 S/G Blowdown

9. Main Feedline Break

a. Calculate RCS Temp. for 1 S/G Blowdown

b. Calculate Time for All S/G to Go Dry

10. Loss of All Feedwater

a. Calculate Time for All Steam Generators to Go Dry

b. Options Available to Cool Reactor. (Opening One PZR PORV)

11. Determination of Inadequate Core Cooling

12. Accident Diagnostics 11.

Title:

Simulator Training Objective: Observation of Actual Abnormal and Accident Conditions and the Identification of Each Topic Summary:

Westinghouse Nuclear Training Center Control Board Familiarization Demonstrations

1. Verification of:

a. Natural Circulation

b. Subcooling

c. Adequate Core Cooling

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2. Major Reactivity Transients

a. Load Rejection with Rods in Manual

b. ATWT c.. Continuous Control Rod Withdrawal from HZP

3. Instrument Failures

4. Small and Large LOCA's

5. S/G Secondary Breaks

6. Pressurizer PORV Open

7. One Spray Valve Open

8. Loss of All Feedwater

9. Loss of Rod Drive MG's Transient Assessment

1. Selected Instrument Failures

2. Selected Accidents

3. Selected Equipment. Failures

4. Multiple Failures A four week course in nuclear and reactor physics was presented for those engineers who did not have previous nuclear engineering education. This course, taught by Memphis State University, is part of an accredited college program, and included the following topics:

Atoms and Matter Light and Electromagnetic Waves Radioactivity and Particle Behavior Nuclear Reactions Fission Reactor Fundamentals Nuclear Fission of Uranium - 235 Neutrons, Reactions, and Moderator Effects Neutron Multiplication Factors Reactivity Reactor Kinetics The Subcritical Reactor On-the-job training, including continuing assignment on-shift as STA, has provided a basic familiarization in plant systems and operation.

Additional Trainin Expanded training for the calendar year 1981 will include:

Plant Design System Operation Transient Response Accident Analysis Simulator Training Procedure Review Technical Specifications Management Skills

Requalification training will commence January 1, 1982, and will continue on a two-year frequency (or until the STA program is phased out). This program will include:

Procedure Review Transient Response Accident Analysis On-shift assignment as STA or on-shift assignment as SRO Evaluations by the Technical Assistant for Operational Assessment Lon -Term STA Pro ram and Trainin Plans The long-term STA program will continue to utilize degreed individuals (with the supplemented education, experience, and training listed above), or individuals with an SRO license who have received the necessary technical education and training. We will replace degreed individuals with SRO-licensed individuals as the licensed individuals receive education'imilar to that outlined in RG&E's letter dated December 28, 1979 from L. D. White, Jr. to Mr. Dennis Ziemann.

The STA program will be phased out when the man-machine interface control room review has been completed and the shift supervisor and senior operator on a shift each meet the proposed future educational requirements of approximately 60 technical credit hours for SRO licensing.

STA Selection and uglification If replacement STA's are required, screening will be performed to ensure candidates meet the education, experience and training requirements of our Administrative Procedure for STA Training prior to their assignment as STA.

Comments on INPO Document and Com arison with RG&E's RG&E has reviewed INPO's document of April 30, 1980 concerning STA Qualifications, Education and Training.

We have concluded that these INPO goals for the STA are "standards of excellence" and represent an ultimate goal. However, lacking guidance from the NRC on minimum requirements for STA, RG&E has established minimum requirements for'TA, independent of INPO's "standard of excellence".

i' We are pleased to offer our comments on the above-mentioned INPO document. We fully endorse the comments and recommendations made by the Mid-Atlantic Nuclear Training Group (MANTG) in a letter, dated October 21, 1980, from MANTG (Young) to INPO (Thomas) and quoted below:

General It is the opinion of the members of the Mid-Atlantic Nuclear Training Group that the subject document's experience, education, and training requirements do not appear to be based upon the demands of the STA position.

As an example, the document includes a position description which lists twelve typical STA responsibilities. Of these, four pertain to evaluating plant conditions during transients or investigating the causes of such very little emphasis is placed on transient conditions transients'et, in the transient/ accident analysis and Emergency Procedures requirements of Section 6.7.

The MANTG recommends that all experience, education, and training requirements be based upon a detailed job/task analysis'hen derived in this manner, the standards will be able to relate to specific knowledge levels, requirements to the typical STA responsibilities. This approach seems especially prudent in light of the recent emphasis of job and task analysis by the Nuclear Regulatory Commission, American Nuclear Standards Institute, and the Institute of Nuclear Power Operations.

2. Pa e 10, Section 5.2 E erience

a. The first paragraph requires the STA to have a minimum of 18 months of nuclear power plant experience.

The MANTG recommends that this requirement be deleted.

It is our opinion that an effective training program will produce a competent STA, regardless of his previous experience.

It should be noted that INPO did not publish this requirement, even in draft form, until May of this year. With the NRC requiring fully trained STA's by January 1, 1981, it will be impossible to staff the STA position with personnel who meet both the require-ments of the NRC and INPO, unless they are drawn from the existing plant staff.

b. Paragraph three states that a maximum of three months of training may be applied toward the experience requirement. The MANTG recommends that both on-the-job training and plant specific systems or operations train-ing which is conducted by or for the facility at which the STA is qualifying, be equivalent to experience on a one-to-one basis with no maximum. The rationale for

l 10 this recommendation is that training at the plant provides the trainee the opportunity to trace systems and observe plant operations which the MANTG feels fulfills the intent of this section.

C. The MANTG recommends that the INPO include a provision in Section 5.2 which equates cold license simulator training to operating plant experience on a three to one basis, similar to the provision presently allowed for cold license operator candidates'a e ll Section 5.3 Absence from STA Duties MANTG recommends that personnel not actively performing STA functions but participating in the STA requalification program, be exempt from the requirements of this section.

Additionally, those persons not performing the function nor participating in the requalification program be required to complete only those portions of the requalification program which they have missed during their absence prior to assigning them for STA duty.

Pa e 13, Section 6.1.2 Colle e Level Fundamental Education

a. In the Electrical Sciences section, the MANTG recommends that Circuit Theory and Digital Electronics be deleted from the knowledge requirements. The MANTG does not believe that they are pertinent to the understanding of nuclear power plant response or control.

b. MANTG requests guidance on how to obtain this college level knowledge within the short time frame required by the Nuclear Regulatory Commission.

Pa e 15, Section 6.2 A lied Fundamentals-Plant

~Secific The MANTG requests guidance on how to determine what constitutes college level training for Plant Specific topics.

Pa e 17, Section 6.6 General 0 eratin Procedures MANTG recommends that all plant operating procedures which relate to an STA's function be included in this section rather than those as mentioned. These procedures should be identified in the STA task analysis recommended in paragraph 1.

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8. Pa e 18, Section 6.8 Simulator Trainin The first paragraph requires a trainee/ instructor ratio of not more than four to one. This would seem to require at least two instructors for every training session since it is anticipated that STA's will be trained along with the rest of their control room watch section. The MANTG recommends that a 4:1 ratio only apply when only STA's are being instructed in a given course.

b. The HANTG recommends that simulator emphasis include the discussion and demonstration of those actions which operators may take which would either mitigate or aggrevate a transient or accident condition.

9. Pa e 19, Section 6.9 Annual Re ualification Trainin MANTG recommends that a review of the theoretical material presented during STA qualification be included in the requalification program.

1.A.1.3

~ ~ ~ Shift ~

Manning BY letter dat ed December 15, 1980 from L. D. White, Jr.

to Mr. Dennis M. Crutchfield, USNRC, RG&E responded to shift staffing criteria and guidelines for scheduling overtime for licensed operators. The commitments pro-vided in that letter, and proposed alternatives to some of the Staff overtime guidelines, remain unchanged. We have revised administrative procedures to implement a similar'olicy to limit overtime work of people in addition to licensed operators who perform safety related work. Procedure A52.9 has been revised to in-clude limits on overtime worked by auxiliary operators in addition to SROs, ROs and Shift Technical Advisors.

Procedure A52.10 has been implemented to limit overtime worked by health physicist technicians, I&C technicians and key maintenance personnel.

Guidance for the Evaluation and Development of Procedures for Transients and Accidents The Westinghouse Owners Group will submit by January 1, 1981, a detailed description of our program to comply with the requirements of Item I.C.1. The program will identify previous Owners Group submittals to the NRC, which we believe will comprise the bulk of the response.

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12 Additional effort required to obtain full compliance with this item (with proposed schedules for completion) will also be identified, as discussed with the NRC on November 12, 1980.

Design Review of Plant Shielding and Environmental Qualification of Equipment for Spaces/Systems Which May Be Used in Post-Accident Operations.

A discussion of our design review is contained in a letter dated December 28, 1979 from L. D. White, Jr. to Mr. Dennis Ziemann, USNRC. Additional information and schedule are contained in a letter dated December 15, 1980 from John E. Maier to Mr. Dennis M. Crutchfield, USNRC.

II.E.1.2 Auxiliary Feedwater System Automatic Initiation and Flow Indication Part 1: Auxiliary Feedwater System Automatic Initiation RG&E has previously responded to NRC requirements for auxiliary feedwater systems in letters dated November 28, 1979, December 14, 1979, December 19, 1979, March 28, 1980, May 22, 1980, May 28, 1980 (2 letters) and July 14, 1980. No changes to the requirements have been identified which require additional information.

Part 2: Auxiliary Feedwater System Flowrate Indication The Design Criteria and Flow Diagram for the modification of the Auxiliary Feedwater Flow Indication is provided in Appendix A. Some of the salient features of the design are:

Redundant flow indication is provided for each motor driven auxiliary feedwater pump (MDAFP) and the common discharge of the turbine driven auxiliary feed-water pump (TDAFP).

2. Each redundant channel of flow indication consists of a: 1) qualified transmitter, 2) transmitter power supply, 3) square root extractor, 4) output isolation amplifier, and 5) main control board analog indicator.

3. Indication is provided to the Operator by means of a dual movement vertical scale indicator. Each move-ment receives the analog signal from its respective channel of flow indication for a particular

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13 auxiliary feedwater flow path. Hence, the Operator can quickly ascertain between channels.

if there is any discrepancy

4. Each channel of flow indication is powered from a separate battery-backed vital instrument bus. In addition, each flow channel's analog instrumentation is mounted in a fully qualified instrument rack.

5. Testability features have been provided in the design, including local flow indication near the auxiliary feedwater pump that will facilitate periodic loop calibration.

6. The Ginna Station Quality Assurance Program will be utilized in the design, procurement, installation and testing of this modification.

7. As mentioned in paragraph 3 above, continuous display of both channels of flow indication will be provided to the operator on the main control board.

8. The flow transmitters installed as a part of this modification are included in Rochester Gas and Electric's program of Environmental Qualification of Foxboro Transmitters being conducted by RG&E and a number of other utilities, and will be qualified to the requirements of NUREG-0737.

II.E.4.2 Containment Isolation Dependability The purge and vent system at, Ginna consists of four 48 inch isolation valves. The Staff's interim position on containment purging (now called Position 6) was im-plemented on these valves by our December 14, 1979 and May 29, 1980 letters. During a recent review of Position 6, it was postulated that two 6 inch valves on our con-tainment depressurization line may be interpreted as falling under Position 6 requirements. These valves are not used for containment purge and vent operations but are used periodically to equalize pressure between inside and outside containment.

Preliminary analysis supplied by the vendor of these valves indicates that the most severe flow condition loading will not stress the valves beyond their standard design limits. The analysis also demonstrates that the valves will close as fast or faster with flow than with-out flow., Therefore, no restrictions need be placed on valve position, but an interim restriction will be placed on the amount of time these valves are open until the final analysis is complete.

PP A valve qualification program for these 6 inch valves will be done in two phases:

To provide further assurance of valve operability following post-accident closure, a more detailed analysis will be performed.

The second phase will consist of seismic and environmental qualification of the entire valve and actuator assembly.

We will inform you of the results upon their completion.

The depressurization valves will only be used to equalize pressure between inside and outside containment, to prevent an unacceptable buildup of containment pressure during normal operation. Whenever containment depressurization is required, emphasis will be placed on limiting de-pressurization times to as low as practical. We do not have at this time sufficient operating experience with limited depressurization to predict what containment pressure fluctuations may occur during plant operation

,to commit to a specific depressurization time limit.

However, all practical efforts will be made to limit depressurization times to the 90 hour0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> per year goal while critical. Should this goal be exceeded, we will inform you and provide a summary of the reasons for exceeding the 90 hour0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> goal.

The containment isolation pressure setpoint will be reduced to 4 psig. Our revised operation for contain-ment depressurization may result in containment pressures of 2 psig. Normal instrument errors and drift may amount to as much as 1 psig (~1% of range). An addi-tional 1 psig margin should be added to assure that in-advertent isolation of containment does not take place since this same signal also trips the reactor and starts safety injection. We will continue to monitor containment pressure. it If is feasible to reduce the 4 psig setpoint pressure, we will inform you.

Noble Gas Effluent Monitor Information concerning our plans for monitoring noble gas effluents was contained in a letter dated December 15, 1980 from John E. Maier to Mr. Dennis M. Crutchfield, USNRC. Additional information will be provided by February 1, 1981.

'h 15 II.F.1.3 Containment High Range Radiation Monitor A Victoreen Model 875 High Range Containment Area Monitor System has been purchased for installation by January 1, 1982. The system is currently being qualified to IEEE-323 and Regulatory Guides 1.97 and 1.89, with test reports expected to be completed by March 1981.

Until those tests are complete, however, we cannot commit that the installed system will meet all of the NRC requirements.

II.F.1.4 Containment Pressure Monitor The Staff position presently calls for "continuous recording" of containment pressure; it is felt that this would result in a waste of paper and unnecessary wear on the recorder mechanism. A system is proposed, however, that will start recording whenever a safety injection or containment isolation signal is present.

This proposed system will provide adequate recording of signals.

II.F.1.5 Containment Water Level Monitor Information concerning RG&E plans to install containment water level instruments is contained in RG&E letters dated December 15, 1980 from John E. Maier to Mr. Dennis Crutchfield and November 19, 1979 from L. D. White, Jr.

to Mr. Dennis Ziemann.

Instrumentation for Detection of Inadequate Core Cooling RG&E's position concerning inadequate core cooling instru-mentation is contained in letters dated December 15, 1980 from John E. Maier to Mr. Dennis Crutchfield and July 2, 1980 from L. D. White, Jr. to Mr. Crutchfield.

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16 II.K.2.13 Thermal Mechanical Report -- Effect of High-Pressure

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Injection on Vessel Integrity for Small-Break Loss-of-Coolant Accident with No Auxiliary Feedwater To completely address the NRC requirements of detailed analysis of the thermal-mechanical conditions in the reactor vessel during recovery from small breaks with an extended loss of all feedwater, a program will be completed and documented to the NRC by the Westinghouse Owners Group by January 1, 1982. This program will consist of analysis for generic Westinghouse PWR plant groupings.

Following completion of this generic program, additional plant specific analyses, if required, will be provided.

A schedule for the plant specific analysis will be determined based on the results of the generic analysis.

II.K.2.17 Potential for Voiding in the Reactor Coolant System during Transients The Westinghouse Owners Group is currently addressing the potential for void formation in the Reactor Coolant System (RCS) during natural circulation cooldown condi-tions, as described in Westinghouse Letter NS-TMA-2298 (T. M. Anderson, Westinghouse to P. S. Check, NRC). We believe the results of this effort, will fully address the NRC requirement for analysis to determine the potential for voiding in the Reactor Coolant System during anticipated transients. A report describing the results of this effort will be provided to the NRC before January 1, 1982.

II.K.2.19 Sequential Auxiliary Feedwater Flow Analysis The Transient Analysis Code, LOFTRAN, and the present, small break evaluations analysis code, WFLASH, have both undergone benchmarking against plant information or experimental test facilities. These codes, under appropriate conditions, have also been compared with each other. The Westinghouse Owners Group will provide on a schedule consistent, with the requirement of Task II.K.2.19, a report addressing the benchmarking of these codes.

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- 17 II.K.3.1 Installation and Testing of Automatic Power-Operated

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Relief Valve Isolation System And II.K.3.2 Report on Overall Safety Effect of Power-Operated Relief Valve Isolation System The Westinghouse Owners Group is in the process of developing a report (including historical valve failure rate data and documentation of actions taken since the TMI-2 event, to decrease the probability of a stuck-open PORV) to address the NRC concerns of Item II.K.3.2.

However, due to the time-consuming process of data gathering, breakdown, and evaluation, this report is scheduled for submittal to the NRC on March 1, 1981. .As required by the NRC, this report will be used to support a decision on the necessity of incorporating an automatic PORV isolation system as specified in Task Action Item II.K.3.1.

II.K.3.5 Automatic Trip of Reactor Coolant Pump During Loss of Coolant Accident The Westinghouse Owners Gro'p resolution of this issue has been to perform analyses using the Westinghouse Small Break Evaluation Model WFLASH to show ample time is available for the operator to trip the reactor coolant pumps following certain size small breaks (See WCAP-9584). In addition, the Owners Group is supporting a best estimate study using the NOTRUMP computer cod'e to demonstrate that tripping the reactor coolant pump at the worst trip time after a small break will lead to acceptable results.

For both of these analysis efforts, the Westinghouse Owners Group is performing blind post-test predictions of LOFT experiment L3-6. The input data and model to be used with WFLASH on LOFT L3-6 has been submitted to the Staff on December 1, 1980 (NS-TMA-2348). The information to be used with NOTRUMP on LOFT L3-5 will be submitted prior to performance of the L3-6 test as stated in Westinghouse Owners Group letter OG-45 dated December 3, 1980.

The LOFT prediction from both models will be submitted to the Staff on February 15, 1981 given that the test is performed on schedule. The best estimate study is scheduled for completion by April 1, 1981.

Based on these studies, the Westinghouse Owners Group believes that resolution of this issue will be achieved

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18 without, any design modifications. In the event that this is not, the case, a schedule will be provided for potential modifications.

II.K.3.12 Confirm Existence of Anticipatory Reactor Trip Upon Turbine Trip An anticipatory trip upon reactor trip exists at the R. E.

Ginna plant as shown in drawing 882D612, Sheet 2, Revision 3 and Sheet 3, Revision 2, provided with a letter dated January 18, 1979 from L. D. White, Jr. to Mr. Dennis Ziemann.

II.K.3. 17 Report on Outages of Emergency Core Cooling Systems Information on ECCS equipment outages is contained in Table II.K.3.17. The information in Table II.K.3.17 was compiled in response to Mr. D. G. Eisenhut's May 7, 1980 letter concerning Five Addition TMI Items and does not include the corrective action taken, a recent change in the requirements. Nevertheless, as seen from the table, most. outages were the result of routine maintenance and inspections. In cases where a violation of Technical Specifications did occur, the corrective action taken is documented in Licensee Event Reports filed with NRC. We have reviewed the ECCS equipment outages and determined that. no action is required at this time. Malfunctioning steam admission valves, the cause of lengthy turbine-driven auxiliary feedwater pump outages, were replaced in May, 1980.

Improving Licensee Emergency Preparedness - Long Term At this time'e believe we will be able to comply with the implementation schedule established for this item.

However, we plan to comply with the requirement for a prompt notification system primarily with the installa-tion of sirens. We do not yet have a commitment for supply of the sirens because field work necessary to establish sound levels, siren locations and the number of sirens required is not yet completed. If it becomes necessary to request an extension of the implementation

' date as this work proceeds, we will notify you promptly.

4 19 The emergency plans required to be submitted by January 2, 1980 concerning radiological emergency response plans will be provided by separate correspondence.

III.D.3.4 Control Room Habitability Requirements The information requested in Attachment 1 to item III.D.3-4 is not being submitted by January 1, 1981 for the reasons given in a letter dated November 24, 1980 from L. D. White, Jr. to Mr. Dennis M. Crutchfield, USNRC.

TABLE LI.K.3.17 PI>AHT T.S.

DATE TIHE OP1HATIffG TIME DATE TIME KUIPMBlT REASOH IHOPHQBIB IHOPHfABIR IHOPHMfiE ffODE

• ALTDWANCE OPHQBIE )OHRABIZ A HfH Pump M-11.15 Inspection and 6/14/76 24 Hrs. 6/14/76 181 1 11 Hours Maintenance 11 Hinutes Bus 14 Supply from 1A Diesel N-15 &t: H-52.1 Breaker 7/9/76 7/9/76 1510 5 Hours Inspection a Maintenance 4 Mimtes B Aux. F.W. Pump H-11.5c Maintenance End 7/20/76 1110 N/A 7/20/76 15K 4 Hours Bearing Cover Gasket 20 Minutes fA Cont Spray Pump Discharge N-64.1 Defective 'A'ontact Valve 860A - Manual open curcuit 8/2/76 24 Hrs. 8/2/V6 1412 4 Hours 27 Minute Turbine Drive APWP Maintenance-ftydraul ic 7/22/76 N/A 7/25/76 1700 2I Hours Control Valve. 5 Minrteo A Component Cooling Pump N-11.27 &c H-.45.1A Inspection 8/17/76 C.S.D N.A. 8/20/V6 1530 81 Hours

&: Naintenance 50 Minutes B Diesel Generator Bus 16 Breaker-Replaced 8/21/76 C.S.D N/A 8/22/V6 18 Hours Secondary Contacts 27 Hfmrtes f1'515 A Service Water Pump M-f f.10 0, H-45.1A Prrmp ard 11/4/76 H/A 11/4/76 6 Hours Motor Inspection &c Maint. 45 Minutes Service Water Pump M-11.10 &r. H-45.1A Pump ard 11/5/76 N/A 11/8/76 78 Hours Motor Inspection Sc Haint. 59 Himrtes B Service Water Pump M-11.10 &r. H-45.1A Pump ard 11/9/76 N/A 11/9/76 1245 5 Hours Motor Inspection 4 Maint. 45 Minutes AOV~6A From Spray Addative YIC-836A Controller Failure.

Tank NaOH 1 1/17/76 1100 24 Hrs. 11/17/76 7 Hours 30 Minutes

• 0 Plant operating at power; C.S.D. Cold Shut Down; H.S.D. . Hot Shut Down

• • Ginna has Service Mater Pumps. Only two are required for post-accident operation

&r {FSAR Table 9.6-1)

Sheet 1 of 12

TABLE II.K.3.'17 (Cont'd.)

PLANT T.S. TIME DATE TIME OPERATINB TIME DATE TIME OUP OP EQJIPHBIT RPASON INOPEBABLB INOPHQBIB INOPHQBIB MODE ALIDWANCB OPERABLB OPHUQKB SERVICE C Service Water Pump M-11.10 &: M-45.1A Pump end 11/9/76 1515 N/A 12/21/76 1245 41 Bys Motor Inspection and 21 Hours Maintenance 30 Mimtes A Service Water Pump (M-32,M-32') 3/28/77 N/A 3/28/77 1525 35 Mirutes AI&0 on Breaker C Service Water Pump {M-32,M-32')

AI&0 on Breaker 3/28/77 N/A 3/28/77 1450 1 Hour 50 Minutes B Service Water Pump Breaker AI&0 Inspection 3/24/77 N/A 3/24/vv 1 Hour 50 Mimtes 1C SIS Pump Bus 14 Breaker Replaced Secondary Contacts 1/3/vv 24 Hrs. 1/3/vv 1150 2 Hours on Breaker 50 Minutes 1B Boric Acid Transfer Pump Breaker Pulled to Perform 24 Hrs. 3/7/77 1145 3 Hours Maint. on C.B. Sritch. 15 Minutes B Service Water Pump Divers cleaning suction 6/1o/77 1030 N/A 6/1o/vv 1100 30 Mirutes screen A&9 Service Water Pumps Divers cleaning suction 6/10/77 N/A 6/1o/vv 1020 1 Hour screen 20 Mimtes C SIS Pump Bus 14 Breaker Breaker failed to close 6/29/77 24 Hrs. 6/29/77 1720 3 Bours during P.T. 50 Minutes D Service Water Pump Divers cleaning suction 6/9/77 N/A 6/9/vv 2 Hours screen 30 Minutes Check Valve leaking v/>>/77 1430 24 Hrs. v/>>/vv 1945 5 Hours 15 Minutes

• +* AI&0 Annual Inspection and Overhaul Sheet-2 of 12

S TABLE II.K.3.17 {Cont'd.)

PLANT T.S. TINE DATE TINE OPERATING TIME DATE OVP OP KQIPM1I1T REASON INOPERABIB INOPERABLE INOPHQBLB NODE ALMNANCE OPERABLE SERVICE Turbine Driven ABF Steam edmission valve problem 6/1/77 1140 N/A 7/1 1/77 1400 40 Days MOV 3504 2 Hours 20 Mimtes Boric Acid Pumps Ec CVCS Repair Valves 398 ABB 8/23/vv N/A 8/23/vv 1525 40 Minutes Valves Sc Piping B D/G Bus 16 Breaker Breaker would not close 9/14/77 0706 168 Hrs. 9/14/77 1030 3 Hours 24 Nimtes 1A Component Cooling Pump Calibration of press 9/26/77 1106 24 Hrs. 9/26/VV 1330 2 Hours transmitter 24 Minutes A Service Water Pump Scheduled Motor Overhaul 10/19/77 0700 N/A 11/8/7l 20 Days 6 Hours B Component Cooling Pump to check coupling alignment 11/15/VV 0800 24 Hrs. 11/15/77 1719 9 Hours 19 Minutes B Component Cooling Pump Check Coupling Alignment 11/16/Tl 1300 24 Hrs. 11/16/77 1445 1 Hour 45 Mimtes Na51 Tank Isolation Valves Repair Valves 12/3/77 0100 H.S.D. 48 Hrs. '1 2/3/Yl 1445 13 Hours 45 Minutes Isolated to repair leaks 12/3/77 0100 H.S.D. 48 Hrs. 12/3/77 1445 13 Hours 45 Mirutes B Charcoal filter Low Air Plow Alarm 1/6/78 2135 24 Hrs. 1/v/v8 1641 19 Hours (C Recirc Pans) . 6 Minutm Sheet 3 of 12

f

'I t

TABLE II.K.3.17 (Cont'd.)

KQiT T.S. TIME DATE TIME OPERATING TIME DATE TIME OUP OP EVIPMENT INOPHUSIR INOPHUSIB MODE ALTlSANCE OP HEEBIE OPHQBIR SERVICE B Service Water Pump Rotor Overhaul 12/12/77 0930 N/A 1/6/78 25 Days 1 Hour 43 Mitutes A Service Water Pump Breaker Inspection 3/16/Vs 0900 N/A 3/16/78 1440 5 Hours 40 Minutes D Service Water Pump Breaker Inspection 3/16/78 1445 N/A 3/16/78 1530 45 Minutes B Service Water Pump Breaker Inspection 3/14/78 1245 N/A 3/14/Vs 1525 2 Hours 40 Mirutes C Service Water Pump Breaker Inspection 3/14/78 1515 N/A 3/14/78 1603 48 Mirutes C Service Water Pump Clean Intake Screen 5/26/78 C845 N/A 5/26/78 1250 4 Hours 5 Minutes A Service Water Pump Clean Intake Screen 5/26/78 0845 N/A 5/26/vs 4 Hours 5 Minxtes B Diesel Generator Inspection 3/27/VS 0400 C.S.D. N/A 3/31/78 1656 4 Days 12 Hours 56 Mimtes C. Service Water Pump Work cn expansion Joint 5/3/78 1030 N/A 5/4/78 1010 23 Hours 40 Minutes Valve 860 B Dischara: from Valve would not stroke closed 6/29/78 1230 24 Hrs. 6/29/78 1 245 15 Minutes Containment Spray Pump A Service Water Pump Inspection 4 lubrication 6/7/78 1120 N/A 6/7/78 1448 '3 Hours 28 Minutes Sheet 4 of 12

/ J p

TABLE IZ.K.3.17 (Cont'd.)

PLANT T.S. TIME DATE TIME OPFRATI?6 TIME DATE TIME OUP OF EQHPMFNT INOPPIABLE INOPERABIR MODE ALMWANCE OPPRABLE OPERABLE SERVICE D Service Water Pump Inspection 8c Lubrication . 6/7/78 1525 N/A 6/7/78 1447 1 Hour 22 Minutes B Service Water Pump Hold for Maintenance 6/7/7 8 0650 N/A 6/V/Ve 5 Hours 30 Mirntes C Service Water Pump Hold for l1aintenance 6/v/vs 1100 N/A 6/7/78 1120 20 Mitutes A Service Water Pump To change expansion ]oint 5/2/78 N/A 5/2/78 1700 Recirc Pans Replace O.B. fan bearing 5/10/78 H.S.D. .

B Cont 0600 N/A 5/11/78 1400 52 Hours B Diesel Bus 16 Breaker Breaker D.C. Control 8/16/78 0700 0 168 Hrs. 8/16/78 1030 5 Hours Malfunction 50 Minutes 1D Containment Recirc Pan Cable Inspection 9/8/78 1430 144 Hrs. 9/8/78 1524 54 Minutes A Containment Recirc Fan To install splicing sleeves 9/18/78 0820 144 Hrs. 9/18/78 1 f50 5 Hours 10 Mimtes 1A RHR HX Outlet HCVA25 Bent Controller Arm 8/51/78 1100 12 Hrs. 8/51/78 1400 5 Hours MOV 852A (RIB)84-209 (Splices) 9/20/78 0851 12 Hrs. 9/20/Ve 1500 6 Hours 9 Minutes MOV 852B (RHR) H4-209 (Splices) 9/19/78 0915 12 Hrs. 9/19/78 1515 6 Hours C Containment Recirc Pan splicing leads 9/27/78 1145 144 Hrs. 9/2l/78 1647 5 Hours 2 Mimtes D Service Water Pump replace bearing 10/16/78 0915 N/A 10/16/78 1430 5 Hours 15 Minutes Sheet 5 of 12

k TABLE XX.K.3.17 (Cont'1.)

PLANT T.S. TIME DATE TIME OPHQTINQ TIME DATE TIHE OUI OF S@IPMBiT INOPHUSIE INOPERABLE MODE AIIDWANCE OPHQBLE OPERABIB SERVICE B Service Water Pump Motor vibration 12/15/78 0845 N/A 12/15/78 1641 7 Hours 56 Minutes 8 Containment Recirc Pump needs splices 9/28/V8 OVOO 144 Hrs. 9/28/78 'I 332 6 Hours 32 Mimtes Turbine Driven AFWP Inspection check for oil 4/2/78 0700 N/A 11/2/78 1410 7 Hours leaks 10 Minutes D Containment Recirc Fans splices 9/22/78 0700 144 Hra. 9/Zl/78 1140 124 Houn3 40 Hi>utes A Containment Recirc Fans splicing install sleeves 9/26/78 0600 168 Hrs. 9/26/78 1215 6 Hours 15 Minutes 1C SI Pump (Bus 14) Start Failure 1/3/V9 24 Hra. 1/3/79 1255 1 Hour 58 Mimtes 1A Diesel Generator Jjube Oil Cooler Hi OP **"* 1/8/79 0905 7 Days 1/8/79 1230 3 Hours 25 Minutes HOV 851B (R1E) would not re-open 2/6/79 Coastdawn 12 Hra. 2/6/79 1715 1 Hour 15 Mimtes A Diesel Generator PT-12.1 2/6/79 0700 7 Days 2/6/79 0935 2 Hours 35 Minutes overpressure protection Maintenance on valve PCV V/1V/V9 0700 C.S.D. 8 Hrs. 7/17/79 1455 7 Hours system 431C 55 Hirutes B Service Water Pump Inspect Motor Bearings 6/6/79 1015 N/A 6/11/79 1110 5 Days 55 Minutes

• +** OP Oil Pressure Sheet 6 of 12

rI J TABLE XX.K.3.17 (Cont'd.)

KANT T.S.

DATE TIME OPFRATIt6 TIME DATE TIME INOPERABIR INOPHtABIS MODE ALMWANCE OPZRABIR OP BRAES overpressure protection 8 Hrs. .

PORV MOV 5I5 & 5t6 closed 7/18/79 0710 C.S.D. 7/18/79 1314 6 ttours sys 430 4 431C 4 Minutes Overpressure Protection Sys. Mov 516 closed slight 7/18/79 1413 C.S.D. 7 Days 7/18/79 1540 1 Hour PCV 430 leakage 27 Mimtes B Service Water Pump Change Oil 7/26/79 0830 C.S.D. N/A 7/26/79 1320 4 Hours 50 Minutes 1C Service Water Pump Change Oil 7/25/79 08>> C.S.D. N/A 7/25/79 1345 5 Hours 32 Mimtes 1D Service Water Pump Change Oil 7/24/79 0330 C.S.D. 7/25/79 08I3 28 Hours 43 Minutes Cont Spray Pump Dischargs did not come off seat on 4/24/79 1048 N/A 4/24/79 l05'3 5 Minutes Valve 860C first try A Service Water Pump 6/18/79 0630 N/A 7/12/79 1312 26 Days 6 Hours 42 Minutes Turbine Driven Aux. PW Pump Steam Admission Valve 3505 8/2/79 1915 H.S.D- to N/A 8/3/79 2050 1 Day Motor Inoperative C.S.D. 1 Hour 35 Mimtes Turbine Driven Aux. Peed. MOV 3505 did not open 8/4/79 1300 N/A 8/Zl/79 1450 23 Days Pump properly 1 Hour 50 Mirutes 1A Component Cooling Water svitch in Pull-Stop for 9/7/79 1110 24 Hours 9/7/79 1125 13 Mimtes Pump performance of CP-617.0 Sheet 7 of 12;

f j

TABLE II.K.3.17 (Cont'1.)

KANT T.S. TIME DATE TINE OPI3ATING TIME DATF, TIME OR OP REASON INOPHQBIB INOPERABIR INOPHQBIR NODE AIZOWANCE OPERABIR OPERABIR SERVICE B Diesel Generator Diesel to breaker to Bus 16 9/13/79 0555 7 Days 9/13/79 0930 3 Hours wouldn't close 35 Minutes 1A 11otor Driven Aux. Peel Pips supports removed 8/29/79 1100 N/A 9/4/79 1530 6 Days Pump 4 Hours 30 Minutes Turbine Driven Aux. Peed Pump will not operate under 9/10/79 1130 7 Days 9/14/79 1450 4 Days Pump steady state conditions 3 Bours 20 Minutes 1B Emergency Diesel Naintainance (Clean oil 9/24/79 0730 0 7 Days 9/29/79 1400 5 Ihgrs Generator cooler) 6 Hours 30 Minutes "D" Standby APP Ioose Anchor Bolts 9/9/79 1520 7 Days 9/20/79 1400 22 Hours 40 Mirutes B Diesel Generator clean inlet cooler 10/16/79 2020 7 Days 10/16/79 2350 3 Hours 30 Minutes Steam Driven A.P.P. Hain'tenance 10/17/79 1120 7 Days 10/18/79 1520 K Hours Power Supply to V-3996 Rewiring 11/5/79 0840 7 Days 11/15/79 1120 2 Hours Turbine Driven 1%lP 40 Hirutes 1B Aux. Peed. Pump PT Calibration 11/16/79 1015 7 Dsys 11/16/79 1200 1 Hour 45 Hinutes 1A Aux. Feed Pump CP-2001 11/16/79 1352 7 Days 11/16/79 1600 2 Hours 8 Mitutes "C" Containment Recirc. Fan Iew Flow Alarm 11/1'7/79 2230 7 Days 11/18/79 1050 12 Hours 20 Minutes Sheet 8 of 12

l>>

TABLE II.K.3.17 (Cont'd.)

PLANT T.S. TIHB DATE TINE OPERATING TIME DATE TIME IJP OP IQlIPMENT REASON INOPFRABIB INOPHlABIB INOPHlABIR HODB ALIDWANCB OPERABLB OPHlABIB SERVICE Steam Driven Aux. Peed. Pump Field PT-16 11/19/79 1315 11/19/79 1340 25 Hirutes Steam Driven Aux. Peed. Pump Closed governer valve in 12/2/79 1145 12/3/79 0400 16 Hours order to isolate Steam 15 Minutes Blowdown (BD) Tank N2 Accumulator for PCV-430 Inx N2 Pressure because of 12/9/79 '200 C.S.D. 7 Days 12/10/79 1248 24 Hours (V801A Pressure) PROV V-8600A repair 48 Hinutes Boric Acid Storage Tanks B.A. ppm below specs. 12/17/79 1340. 12/19/79 1315 47 Hours

'35 Mirutes "B" Service Water Pump Noise in motor >>/n/79 0830 N/A 1/15/80 1010 49 Days 1 Hour 40 Hirrrtes "A" Diesel Generator Would not accept more than 1/18/80 0710 1/18/80 1250 5 1kers 1KO kw 40 Hinutes "1D" Service Water Pump Hold for pump repacking 1/22/80 0610 N/A 1/22/80 1455 8 Hours 45 Minrtes 1A RHR Pump 2/8/80 1030 24 1hurs 2/8/8O 2 Hours 1B RHR Pump 2/8/80 1231 24 Hours 2/8/80 1436 2 Hours 5 Minutes "1C" Standby Aux. Peed Pump Change Oil, install 2/19/80 1000 2/20/80 1500 Thermo couples "D" Standby Aux. Feed Pump Change Oil, install 2/21/80 0830 2/22/8) 1110 26 Hours The rmocouples 40 Minutes Sheet 9 of 12

4 J TABLE II.K.3.17 (Contrd.)

PLANT T.S. TIME DATE TIMF. OP FRATING TIMF, DATE TINFi OUZ OF RFAHON INOPH1ABLFi INOPERABLE INOPNABLFi MODE ALIOWANCE OPERABLFi OPERABM SERVICE MIIPNENT "C" StandbJJ Aux. Feed Pump Change Oil 3/17/M 0820 3/21/M 1100 98 Hours 40 Minutes MOV-73% CC to RllR 11X Clutch problem with 5/12/80 2210 H.S.D. 5/12/80 1 Hour Limitorriue 35 Mirutes "A" RllR Prrmp Leaking Heal 5/17/80 C.S.D. N/A 5/19/80 53 Hours 5 Minutes "1B" Boric Acid Pump Replacement of PT-110 5/19/80 1150 C.S.D. N/A 5/19/M 2130 9 Hours (N-12.1) 40 Mirutes "1A" Boric Acid Pump Replacement of PT-110 5/19/M 1150 C.S.D. N/A 5/19/80 2130 9 Hours (N-12.1) 40 Minutes Driven .in Motor 5/22/8O 1130 H.S.D. 5/22/eo 2 Hours NOV-3505h h Turbine Ground 20 Mirutes Aux. Feed Pump.

llOV-3504A Main Steam from Grounded Motor 5/22/eo 1015 H.S.D. 5/22/eo 1350 3 lhurs 1B Stadia Generator to AFP 35 Minutes Concentration Tank A- 4/20/79 1450 N/A 4/20/V9 1735 2 Hours Boric Acid Storage Tank Ixrw 45 Mirutes 12.9f Tank B-11.85 Go to H.S.D 4/16/79 1440 1 Hour Boric AcM Storage Tank Low Concentration Tank A8cB- 4/16'?9 11.% 50 Minutes lligh Concentration Tank AM- 8/31/79 Go To C.S.D e/31/V9 4 Hours Boric Acid Storage Tanks 6 Mirutes 13.0f Level dropped to 5/22/eo 15'30 H.S.D 1 lhur 5/22/M 1615 45 Mirutes Accumulators 48r'ow Boric Acid Storage Tanks Concentration (11.9) to 7/11/8O 1045 Go To H.S.D 7/1 1/M 1553 5 Hours (11.8r') 8 Minutes Sheet 10 of 12

e TABLE XI.K.3.17 (Cont'd.)

KANT T.S. TIME DATE TIME OP HATING TIME DATB TIME OGP OP REASON BSPHQBIB INOPHQBIB INOPERABIE 5$ DE ALIOWANCE OPERABIE OP BRAKE SERVICE Boric Acid Storage Tanks High Concentration (14.4$ ) 7/14/M 1020 Go to H.S.D 7/14/80 1530 5 Hours 10 Minutes "B" Boric Acid Storage hw Concentration (11.8r') 7/14/80 Go to H.S.D 7/14/80 1 Hour Tank 35 Mirutes "A" Service Water Pump Minor Maintenance v/e/80 0820 N/A 7/8/M 1340 5 Hours 20 Minutes "D" Standby Aux, P.W. Pump N-11.14 Annual Insp. and 6/24/80 7 Days 6/25/80 1015 33 Hours maintenance 15 Nirutes "C" Standby Aux. P.W. Pump M-11.14 Annual Insp. and maintenance 6/25/M 11 10 v ~ 6/27/80 1427 51 Hours 17 Minutes "D" Service Water Pump Minor inspection 7/3/80 N/A v/3/M 1425 6 Hours 25 Hirutes "D" Service Water Pump M-11.10.1 Minor Inspection 7/30/M N/A V/30/M 1029 5 Hours 59 Minutes 1B Emergency Diesel M 32 1 ~DB 25~D~~DB 75 9/10/80 7 Days 9/10/80 4 Hours Generator Circuit Breaker Naint R OC 41 Hirutes Trip Device Test and/or Re-placement "A" Aux. P.W. Pump (Notor CP 2001.0 1A Motor driven 9/8/M 7 Days 9/8/M 1440 5 Hours Driven) Aux. PW. Pump discharge flrnr 45 Minutes loop 2001 "D" Service Water Pump M-11-10.1 Minor Inspect. of 8/1 9/80 N/A 8/20/M 1315 13 Hours SWP Packing leak 45 Minutes Sheet ll of 12

k~

TABLE IX.K.3.17 (Cont'd.)

INOPERABLE PLANT T.S. TINE DATE TINE OPERATING TINE DATE TINE OUP OP INOPHQBIR HODE ALIlNANCE OPERABLE OPERABIB SERVICE "1B" Emergency Diesel H-32.1, DB-25, DB-50, DB-75 9/10/80 9/10/8) 4 Hours Generator circuit breeker maintenance 41 Hinutes and OC Trip Device Test and for replacement A Bnergency Diesel Gener- Operability Questioned 10/3/80 10/3/8) 1113 1 Day ator see LER 80-9 4 Hours 24 Hinutes Turbine Aux. Peedwater Pump SN-79-18 32,B 10/2/80 0 10/3/80 1115 3 Hours 15 Himtes Spray System To APP Oil SN-83-1833.6 Installation of 10/20/80 10/25/80 4 Days resorvoir Aux./Int. Building Loop Pire 21 Hours Supression Valves Sheet 12 of 12

f ~

APPENDIX A Design Criteria Auxiliary Feed Pump Instrumentation Upgrade Ginna Station Rochester Gas and Electric Corporation 89 East Avenue Rochester, i4ew York 14649 ENR-1869 Revision 1 May 5, 1980 Prepared by:

0, sin(se DATE Responsi le ngineer Reviewed by:

l3 80 DATE Qua ty Assurance Engineer, Design Approved by: 0I/ I DATE Manager, Mechanical Ehgineering Page 42 92

I lF

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Revision Status Sheet Latest Latest Lati.st Pape Rev. Page Rev. Page Rev.

Criteria Revision sign.

5/5/80 EWR 1869 Page ii 42 91

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Desi Criteria 1.0 Summar Descri tion of the Desi Summary 1.1.1 The purpose of this modification is to upgrade the flow and pressure instrumentation associated with the motor driven and turbine driven auxiliary feedwater pumps at Ginna Station. This modification involves the replace-ment of the following primary instrumentation: PT-2029, FT-2001, FT-2009, PT-2019, PT-2030, FT-2002, FT-2006, FT-2007. This instrumentation presently used does not, have the desired accuracy and repeatability.

1.1.2 In addition, the existing flow transmitters are utilized to operate valves 4007, 3996 and 4008. Each of these flow transmitters have a built in switch which is actuated via a mechanical linkage. This mechanical linkage has enough inertia such that accurate and repeatable determination of switch actuation point is not possible. As part of this modification, these switches will be replaced with electronic bistables, which electronically compare flow transmitter output with setpoint and change 'state when the setpoint is reached.

To satisfy the requirements of reference 2.5 below, additional channels of flow instrumentation will be added to each auxiliary feedwater pump. This additional channel will be of the opposite channel designation from that of the primary channel. The primary channel for each feedwater pump will control that particular pump's discharge valve, whereas the secondary channel merely indicates flow. The secondary channel as shown on the above referenced consists of that instrumentation without tag numbers.

1.2 Functions (Reference RGSE drawing 33013-697, t

Rev. 0) 1.2.1 Poop FT-2001 This loop measures the flow in auxiliary feedwater line to the "A" steam generator, The differential pressure measured by FT-2001 is converted to a flow signal by .

FM-2001. Indication of flow on the main control board is provided by FI-2021A. FM-2001A acts as an isolation amplifier to isolate the class IE system from FI-2021B which is not safety related. Electronic bistable FY-2001 functions to position valve 4007 such that the flow matches FY-2001's setpoint. FQ-2001 supplies dc power to this loop.

Design Criteria Revision EWR 1869 1 Date Page 42 90

T.

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1.2.2 Loop FT-2009 This loop measures the total discharge flow of the steam driven auxiliary feedwater pump. FT-2009 measures the differential pressure across its flow element and FM-2005 converts this signal to a flow signal. FY-2005 is an electronic bistable which opens recirc valve CV-27 to maintain minimum flow through the pump, during low flow operations. FM-2009A is an isolation amplifier which isolates local flow indicator FI-2009 from the Class IE safety system. FQ-2009 supplies this loop with dc power.

1.2.3 loop FT-2002 This loop functions exactly the same as the FT-2001 loop with the only difference that this loop monitors the flow of auxiliary feedwater to the B steam generator.

1.2.4 Loops FT-2006 and FT-2007 Both these loops function in the same manner; each loop measures the flow to its respective steam generator from the turbine driven auxiliary feedwater pump and indicates this flow on the main control board. An isolation amplifier for each loop isolates the class IE portion from the non safety local indication located near the turbine driven pump. Each loop also contains a dc power supply.

1.2.5 Loops PT-2029, PT-2019 and PT-2030 Each of these loops are similar and merely monitor the discharge pressure of their respective auxiliary feedwater pump. Indication of discharge pressure for each pump is on the main control board.

1.2.6 For loops FT-2001, FT-2009 and FT-2002 a secondary redundant channel of flow instrumentation is provided.

Each channel consists of a flow transmitter (FT),

sguare root converter (FM), power supply (FQ) and control room flow indicator (FI)..

1.3 Performance Reguirements The sensing elements (the flow and pressure trans-mitters) shall be capable of sensing and producing an output over the range of design values for all possible operating and accident conditions for the particular system in which they are installed.

Design

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Criteria

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Revision EWR 1869 2 Dare 5/5/80 Page 42 90

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Control As outlined in Section 1.1 above, this modification will replace the integral flow switches in the flow transmitters with electronic bistables. This modifica-tion shall in no way affect the control of these valves.

1.5 Modes of Operation 1.5.1 The class IE portion of this modification shall be designed to be operational: 1) during all modes of normal plant operation, 2) after a safe shutdown earth-quake, and 3) after a steam/feedwater line crack break event in the Intermediate Building.

1.5.2 The non Class IE portion of this modification shall be designed for operations during startup, hot shutdown, and power operations.

2.0 Re ferenced Documents 2.1 Rochester Gas & Electric Corporation, Ginna Station Quality Assurance Manual, Appendix A, "Quality and Safety Related Listing and Diagrams", October 1, 1976.

2.2 USNRC'egulatory Guides.

2.2.1 No. 1.29, "Seismic Design Classification", Rev. 2, February, 1976.

2.2.2 No. 1.100, "Seismic Qualification of Electric Equipment.

for Nuclear Power Plants", Rev. 1, August, 1977.

2.3 American National Standards Institute. ANSI N45.2.2 1972, "Packaging, Shipping, Receiving, Storage .and Handling of Items for Nuclear Power Plants".

2.4 Institute of Electrical and Electronic Engineers Standards.

2.4.1 IEEE-323 - 1974, "Standard for Qualifying Class IE Equipment for Nuclear Power Generating Stations".

2.4.2 IEEE-344 - 1975, "Recommended Practices for Seismic Qualification of Class IE Equipment for Nuclear Power Generating Stations".

2.4.3 IEEE-323-1971, "Standard for Qualifying Class 1E Equipment for Nuclear Power Generating Stations" 2.4.4 IEEE-344-1971, "Recommended Practices for Seismic Qualification of Class 1E Equipment for Nuclear Power Generating Stations".

Design Criteria Revision EWR 1869 Page 3

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2.4.5

~ ~ IEEE-383-1975, "IEEE Standard for Type Test of Class IE Electric Cables, Field Splices and Connections for Nuclear Power Generating Stations".

2.4.6 IEEE-384-1974, "Trial Use tandard Criteria for Separation for Class IE Equipment and Circuits".

2.4.7 IEEE-336-1977, "Installation, Inspection and Testing Requirements for Instrumentation and Electric Equipment During Construction of Nuclear Power Generating Stations".

2.5 Letter date November 19, 1979 to D. Ziemann, NRR from L.D. White, Jr. section 2.1.7.b.

3.0 Seismic Cate or 3.1 Based on USNRC Regulatory Guide 1.29 and Appendix A of the Ginna FSAR the following instrumentation is Seismic Category 1: FT-2001, FM-2001, FM-2001A, FI-2021A, FQ-2001, FY-2001, FT-2002, FM-2002, FM<<2002A, FI-2022A, FQ-2002, FY-2002, FT-2006, FM-2006, FM-2006A, FI-2023A FQ-2006, FT-2007, FM-2007, FM-2007A, FI-2024A, FQ-2007I PT-2029, PI-2189A, PQ-2029, PT-2019, PI-2048A, PQ-2019, PT-2030, PI-2190A, and PQ-2030, and all instrumentation used as part of the seondary channel flow indication.

Based on USNRC Regulatory Guide 1.29 and Appendix A of the Ginna FSAR the following instrumentation is not Seismic Category 1: FI-2021B, FI-2023B, FI-2024B, .and FI-2022B.

4.0 ualit Grou Not Applicable.

5.0 Code Class Not Applicable.

6.0 Codes, Standards and Re ulator Re irements 6.1 The non safety related portion of this modification shall be installed as per the requirements of the National Electrical Code, 1978.

6.2 USNRC Regulatory Guide 1.100 defines additional require-ments and changes to IEEE Standard 344-1975, "IEEE Recommended Practices for Seismic Qualification of Class IE Equipment. for Nuclear Power Generating Stations". Implementation of this standard for procurement of Class IE instrumentation will include the requirements of this Regulatory Guide.

Design Criteria Revision 1 EWR 1869 4 Date 5 5 80 Page 42 90

p 6.3 IEEE-336-1977 shall be used as a guideline during the installation, inspection and testing phase of this modification.

7.0 Desi Conditions 7.1 Flow and Pressure Transmitters 7.1.2 Fluid Pressure 1550 psig 7.1.3 Fluid Temperature 40 to 120'F.

7.1.4 Current, 10 to 50 mAdc 7.2 Electric Instrumentation Current, 10 to 50 mAdc 7.3 Instrumentation Power Supplies 7.3.1 Input Voltage 118 volts 60hz 1P 7.3.2 Output Current 10 to 50 mAdc 7.3.3 Maximum Load 660 ohms Load Conditions The instrumentation listed in Section 3.1 shall be designed to withstand the effects of a safe shutdown earthquake (0.2g base ground motion) without a loss of function.

9.0 Environmental Conditions 9.1 Intermediate Building Normal Accident.

9.1.1 Temperature 40 to 104 F 215oF 9.1.2 Pressure atm. 1.0 psig 9.1.3 Relative Humidity 0 to 100% 100%

9.1.4 Radiation (5R/hr gamma accumulative) 9.2 Control Room 9.2.1 Temperature 65 to 85 F. 40 to 120'F.

9.2.2 Pressure atm. atm.

9.2.3 Humidity 15 to 95% 15 to 95%

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9.2.4 Radiation negligible negligible 9.3 Relay Room 9.3.1 Temperature 40 to 104 F. 40 to 104 F.

9.3.2 Pressure atm. atm.

9.3.3 Humidity 15 to 95% 15 to 95%

9.3.4 Radiation negligible negligible 9.4 New pressure and flow transmitters required by this modification shall be environmentally qualified to IEEE-323-1971 and IEEE-344-1971.

9.5 New process analog computational equipment shall be environmentally qualified in accordance with IEEE-323-1974 and IEEE-344-1975.

10.0 Interface Re irements 10.1 Existing cable trays utilized as a routing path for this modification shall be reviewed to ensure that tray capacity is not exceeded.

10.2 Mounting of new electronic instrumentation in existing racks in the Relay Room shall not degrade the capability of those racks to withstand the effects of the safe shutdown earthquake.

11.0 Material Re irements None.

12.0 Mechanical Re irements Flow and pressure transmitters shall be designed for installation at the location of the existing transmitters, and utilizing existing tubing connections.

13.0 Structural Re uirements None.

14.0 H draulic Re uirements None.

15.0 Chemistr Re irements None. ~

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l6.0 Electrical Re uirements 16.1 Instrument cable utilized in this modification shall meet the following requirements:

16.1.1 Size 16 AWG.

16.1.2 Voltage rating 600 volts.

16.1.3 Insulation shall be qualified as pe'r IEEE-383-1975.

16.2 Instrument power shall be from a 120VAC, 60ha, lp Class 1E power supply as follows.

16.2.1 Primary instrumentation power: from same instrument bus as motor (turbine) controls 16.2.2 Secondary flow indication: from opposite instrument.

bus designated by 16.2.1 above 17.0 0 erational Re irements This modification shall not. impose any additional operational requirements under all modes of plant operation as this modification will not change or introduce any additional equipment operations or control.

18.0 Instrumentation and Control Re uirements The instruments utilized in this modification shall have the same basic span, range, and indication as the existing instrumentation.

19.0 Access and Administrative Control Re irements None.

20.0 Redundanc , Diversit and Se aration Re uirements Separation between separation groups 1 and 2 shall be maintained as per IEEE-384-1974 whenever existing plant design permits. Where separation between groups cannot meet this criteria, separation shall be maintained as described in Section 8.2.2 of the Ginna FSAR.

21.0 Failure Effects Re uirements 21.1 This modification shall be designed such that a failure of a separation group 1 component shall not affect the operability of the separation group 2 system.

Design Criteria Revision EWR 1869 7 Da)e 5 5 80 Page i2.90

P'I 21.2 The instrumentation designated in this modification as being in either separation group 1 or 2 shall be designed to withstand the effects of a safe shutdown earthquake with no degradation in performance or accuracy.

21.3 The pressure and flow transmitters installed in the Intermediate Building shall be designed to withstand the environmental effects of a postulated pipe crack with no loss in performance and accuracy.

22.0 Test Re irements 22.1 Tests shall be performed prior to placing this modifi-cation inservice, to ensure that, design requirements have been met.

22.2 Seismic qualification testing of safety related instru-mentation shall conform to the requirements of IEEE-323-1974 and IEEE-344-1975.

22.3 Environmental qualification testing of instrumentation shall conform to the requirements of IEEE-323-1974, or IEEE-323-1971 as described in section 9.4.

22.4 Flame testing of cable utilized in this modification shall conform to the requirements of IEEE-383-1974.

23.0 Accessibilit , Maintenance, Re air and Inservice Ins ection None.

24.0 Personnel Re irements None.

25.0 Trans ortabilit Re uirements None.

26.0 Fire Protection Re uirements Cable used in this modification shall meet the flame spread requirements of IEEE383 1974.

27.0 Handlin Re uirements Electronic instrumentation shall be shipped and stored in accordance with Level B requirements of ANSI N45.2.2.

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28.0 Public Safet Re uirements None.

29.0 ~11't.

Materials and equipment utilized in this modification-shall be chosen such that these design requirements are met.

30.0 Personnel Safet. Re uirements None.

31.0 Uni ue Re uirements None.

Design Criteria Revision EWR 1869 Page 9 Date 5/5/80 42 90

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